      TEXAS COURT OF APPEALS, THIRD DISTRICT, AT AUSTIN


                                      NO. 03-11-00072-CV



        Appellants, State of Texas’ Agencies and Institutions of Higher Learning;
     Office of Public Utility Counsel; Steering Committee of Cities Served by Oncor;
      Oncor Electric Delivery Company, LLC; Alliance of TXU/Oncor Customers;
    Texas Industrial Energy Consumers; CenterPoint Energy Houston Electric, LLC//
                  Cross-Appellant, Public Utility Commission of Texas

                                                v.

     Appellees, Public Utility Commission of Texas; Office of Public Utility Counsel;
 Steering Committee of Cities Served by Oncor; Oncor Electric Delivery Company, LLC;
        Alliance of TXU/Oncor Customers; Texas Industrial Energy Consumers//
      Cross-Appellees, State of Texas’ Agencies and Institutions of Higher Learning;
 Steering Committee of Cities Served by Oncor; Oncor Electric Delivery Company, LLC;
                            Alliance of TXU/Oncor Customers




     FROM THE DISTRICT COURT OF TRAVIS COUNTY, 98TH JUDICIAL DISTRICT
     NO. D-1-GV-10-000137, HONORABLE LORA J. LIVINGSTON, JUDGE PRESIDING



                                         OPINION


               This is an administrative appeal from a final order of the Public Utility Commission

(the Commission) increasing rates charged for electric transmission and distribution services by

Oncor Electric Delivery Company, LLC (Oncor). The district court affirmed all but two of the

disputed issues in the Commission’s order. This appeal involves several appellants and appellees,

raising a total of twelve issues. For the reasons discussed herein, we affirm the district court’s

judgment with respect to eight of the twelve issues and reverse the judgment and remand this cause
to the Commission for further proceedings with respect to the following four issues: (1) whether

the Commission properly determined that Oncor need not offer state colleges and universities a

20% discounted rate; (2) whether the Commission properly excluded from Oncor’s reasonable

and necessary expenses a portion of its requested franchise-fee payments; (3) whether the

Commission properly calculated the “lead-day” figure for the franchise-tax component of Oncor’s

cash-working-capital allowance; and (4) whether the Commission properly determined Oncor’s

federal income-tax expense.


                      FACTUAL AND PROCEDURAL BACKGROUND


Overview of electric utility ratemaking

               Oncor is an electric utility, specifically a “transmission and distribution utility,”

as defined in the Public Utilities Regulatory Act (PURA). See Tex. Util. Code § 31.002(6).

Consequently, its rates are regulated by PURA and set by the Commission in a contested-case

proceeding, referred to as a ratemaking proceeding. See generally PURA §§ 36.001-.406; see also

Tex. Gov’t Code § 2001.003(1). The Commission is required by PURA to set rates 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.” PURA § 36.051. In other words, 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).



                                                  2
               In determining the amount of invested capital used to serve customers, the Commission

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

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

the Commission starts with the utility’s actual expenses incurred during a “test year” and then

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

(2014) (Pub. Util. Comm’n of Tex., Cost of Service). Allowable expenses include such things as

operating expenses, federal income taxes, and employee post-retirement benefits. See id. Together,

a utility’s allowable expenses plus its return on invested capital compose its “cost of service.”

Id. § 25.231(a).

               Thus, PURA directs the Commission to examine financial information taken from

a historical test year and calculate prospective rates based on three factors: (1) the amount of

invested capital that the utility uses to provide service to its customers (the “rate base”); (2) a

reasonable rate of return on that invested capital; and (3) the amount of the utility’s reasonable and

necessary operating expenses (“allowable expenses”). See Suburban Util. Corp. v. Public Util.

Comm’n, 652 S.W.2d 358, 362 (Tex. 1983). Additionally, the Commission determines issues of

“rate design,” which involve determining how to distribute the utility’s revenue requirements among

the various services provided by the utility. See Nucor Steel v. Public Util. Comm’n, 168 S.W.3d

260, 268 (Tex. App.—Austin 2005, no pet.). In a proceeding involving a proposed rate change, the

burden of proving that the rate change is just and reasonable is on the utility. See PURA § 36.006.




                                                  3
Proceedings in this case

               In 2008, Oncor filed an application with the Commission seeking to increase its rates,

supporting its request with voluminous testimony and exhibits constituting its “rate-filing package.”

See id. § 36.351. The rate-filing package accompanying Oncor’s request for an increase included

data based on the 2007 test year. See id. Several other entities (including several appellants and

appellees) intervened to oppose Oncor’s request.

               The Commission referred Oncor’s rate-filing package to the State Office of

Administrative Hearings (SOAH) to conduct hearings (administered by Administrative Law Judges

(ALJs)) on the utility’s requested rate increase. At the conclusion of the hearings, the ALJs issued

a proposal for decision (PFD), which contained the judges’ findings of fact and conclusions of law

recommending that the Commission allow some of Oncor’s requested rate increase. After reviewing

briefing and argument of the parties, the Commission issued its final Order on Rehearing (Order),

wherein it accepted some but also rejected some of the ALJs’ findings and conclusions. See Tex.

Gov’t Code § 2003.049(g) (outlining when Commission may change ALJ’s findings and conclusions).

               Oncor and four other parties involved in the ratemaking proceedings filed suits for

judicial review in the district court, seeking reversal of various aspects of the Commission’s Order.

See PURA § 15.001. The district court affirmed the Commission’s Order in all respects except

regarding two issues: (1) whether Oncor is required to offer a discounted rate to state colleges and

universities and (2) whether the Commission properly excluded from Oncor’s expenses its payments

of municipal franchise fees. With no party entirely satisfied by the trial court’s judgment, each has

appealed portions of it.



                                                 4
Parties to this suit and issues on appeal

               Oncor raises seven issues on appeal, asserting that: (1) the district court erred in

reversing the Commission’s decision allowing Oncor to eliminate the 20% discount it had been

providing to state colleges and universities; (2) the Commission erred in not allowing Oncor to

remove certain deductions from its accumulated-deferred-federal-income-tax (ADFIT) balance;

(3) the Commission erroneously calculated Oncor’s cash-working-capital allowance with respect

to amounts related to the state franchise tax; (4) the Commission erred in not allowing Oncor to

recover certain business restructuring costs; (5) the Commission erred in removing Oncor’s payment

of certain employee-incentive compensation from its cost of service; (6) the Commission erred in

not allowing Oncor to recover its reimbursement of certain municipalities’ regulatory costs; and

(7) the Commission erred in requiring Oncor to prepare a rate-design study addressing the “direct

assignment of costs” methodology as applied to wholesale customers as a rate class.

               The Commission appeals the two issues reversed by the district court. First, the

Commission agrees with Oncor’s position on the university discount. Second, the Commission

asserts that the district court erred in reversing the Commission’s Order denying Oncor’s recovery

of its payment of municipal franchise fees. CenterPoint Energy Houston Electric, LLC (CenterPoint)

also appeals the university-discount issue.

               The Steering Committee of Cities Served by Oncor (Steering Committee) is a coalition

of incorporated municipalities. Steering Committee asserts four issues on appeal, alleging that

the district court erred by affirming the Commission’s decision to: (1) not impose a consolidated

tax savings adjustment on Oncor’s income-tax expense; (2) allow Oncor complete recovery for



                                                5
its expenses incurred in deploying automated meters; (3) base Oncor’s self-insurance reserve

accrual on insufficient evidence; and (4) include pension-related assets in its calculation of Oncor’s

ADFIT balance.

               Four parties join in appealing Steering Committee’s first issue regarding Oncor’s

income-tax expense: Texas Industrial Energy Consumers (TIEC), which represents large industrial

customers; the Office of Public Utility Counsel (OPUC), which is statutory counsel charged with

representing the interests of residents and small businesses; the State of Texas’ Agencies and

Institutions of Higher Learning (State Agencies), which represent public agencies and universities;

and the Alliance of TXU/Oncor Customers (Alliance), which represents residential customers. The

Alliance also joins in appealing Steering Committee’s second issue regarding Oncor’s recovery

for automated meters.


                                   STANDARDS OF REVIEW

               To prevail in an administrative appeal, a party must show reversible error in the

agency’s order. See Anderson v. Railroad Comm’n, 963 S.W.2d 217, 219 (Tex. App.—Austin 1998,

pet. denied); see also Tex. Gov’t Code § 2001.174. The Administrative Procedure Act requires the

reviewing court to reverse or remand a case if substantial rights of the appellant have been prejudiced

because the administrative findings, inferences, conclusions, or decisions are: (a) in violation of a

constitutional or statutory provision, (b) in excess of the agency’s statutory authority, (c) made

through unlawful procedure, (d) affected by other error of law, (e) not reasonably supported by

substantial evidence considering the reliable and probative evidence in the record as a whole, or




                                                  6
(f) arbitrary or capricious or characterized by abuse of discretion or clearly unwarranted exercise

of discretion. Tex. Gov’t Code § 2001.174.

                When reviewing an agency’s fact findings and corresponding legal conclusions, a

court uses the deferential substantial-evidence standard. Substantial-evidence review is limited in

that it requires “only more than a mere scintilla” to support an agency’s determination. Railroad

Comm’n v. Torch Operating Co., 912 S.W.2d 790, 792-93 (Tex. 1995). Substantial-evidence

review “does not allow a court to substitute its judgment for that of the agency.” Id. at 792. As such,

“the evidence in the record actually may preponderate against the decision of the agency and

nonetheless amount to substantial evidence.” Texas Health Facilities Comm’n v. Charter Med.-

Dallas, Inc., 665 S.W.2d 446, 452 (Tex. 1984). The true test is not whether the agency reached the

correct conclusion, but whether some reasonable basis exists in the record for the action taken by

the agency. Id. The findings, inferences, conclusions, and decisions of an administrative agency are

presumed to be supported by substantial evidence, and the burden is on the contestant to prove

otherwise. Id. at 453.

                An agency’s decision is arbitrary and capricious or results from an abuse of discretion

if the agency: (1) failed to consider a factor that the legislature directs it to consider; (2) considers

an irrelevant factor; or (3) weighs only relevant factors that the legislature directs it to consider but

still reaches a completely unreasonable result. City of El Paso v. Public Util. Comm’n, 883 S.W.2d

179, 184 (Tex. 1994). Other reasons an agency’s decision might be considered arbitrary is if its

order denies parties due process of law or the agency fails to follow the clear, unambiguous language




                                                   7
of its own regulations. Reliant Energy, Inc. v. Public Util. Comm’n, 153 S.W.3d 174, 199 (Tex.

App.—Austin 2004, pet. denied).

                We review questions of statutory construction de novo. State v. Shumake, 199 S.W.3d

279, 284 (Tex. 2006). Our primary objective when construing a statute is to give effect to the

legislature’s intent. See id. We seek that intent first and foremost in the statutory text, see id., and

we rely on the plain meaning of the text unless a different meaning is supplied by legislative

definition or enforcing the plain language would produce absurd results, see Entergy Gulf States, Inc.

v. Summers, 282 S.W.3d 433, 437 (Tex. 2009). Additionally, we presume the legislature’s intention

when enacting statutes is to favor the public interest over any private interest and to produce a just

and reasonable result. See Tex. Gov’t Code § 311.021.

                When reviewing an agency’s interpretation of a statute that it is charged with

enforcing, we first consider whether the statute is ambiguous. See Railroad Comm’n v. Texas

Citizens for a Safe Future & Clean Water, 336 S.W.3d 619, 625 (Tex. 2011). If the legislature’s

intent is “clear and unambiguous under the language of the statute, that is the end of the inquiry.”

Id. If the statute is ambiguous, however, we will uphold the agency’s construction if it is reasonable

and in accord with the statute’s plain language. Id. Deference is particularly warranted when the

statutory term at issue is “amorphous,” when the agency oversees “a complex regulatory scheme,”

and when the analysis to be performed “implicates” the agency’s technical expertise. Id. at 629-30.


                                           DISCUSSION

                We begin our discussion with the one issue pertaining to rate design: the discount

for state colleges and universities. We then proceed to a discussion of the five issues pertaining to

                                                   8
rate base, followed by a discussion of the five issues related to reasonable and necessary expenses.

Finally, we conclude our discussion with the one issue not directly affecting the ratemaking in this

proceeding: whether the Commission was authorized to order Oncor to prepare a study about the

direct assignment of costs to wholesale customers.


I.      Rate-design issue: university discount


The dispute and procedural background

                The Commission and Oncor appeal the district court’s reversal of the Commission’s

partial summary decision discontinuing a 20% base-rate discount for state colleges and universities

(university discount). The statute at issue is PURA section 36.351, stating in relevant part,


        (a)     Notwithstanding any other provision of this title, each electric utility and
                municipally owned utility shall discount charges for electric service
                provided to a facility of a four-year state university, upper-level institution,
                Texas State Technical College, or college.

        (b)     The discount is a 20-percent reduction of the utility’s base rates that would
                otherwise be paid under the applicable tariffed rate.


PURA § 36.351 (emphasis added).

                It is undisputed that Oncor is an “electric utility” under this statute. See id. § 31.002(6)

(electric utility defined as person “that owns or operates for compensation in this state equipment

or facilities to produce, generate, transmit, distribute, sell, or furnish electricity in this state” but

specifically excluding power generation companies and retail electric providers).1 The point of


        1
           Oncor is also, indisputably, a “transmission and distribution utility,” defined as a person
“that owns or operates for compensation in this state equipment or facilities to transmit or distribute
electricity.” PURA § 31.002(19).

                                                    9
contention between appellants (the Commission, Oncor, and CenterPoint) and appellees (State

Agencies) centers on interpretation of the phrase “electric service provided to [state universities].”

In other words, does Oncor “provide electric service” to state universities, which are retail customers?

Appellants argue that Oncor does not, as it is statutorily proscribed from providing “retail electric

service” because—since 2002, when utility companies were required to “unbundle” into three

separate entities—only statutorily defined “retail electric providers” (REPs) may perform that

function. State Agencies maintain that Oncor does provide electric service to state universities in

the form of “transmission and distribution service” by delivering electricity to each end-user’s

electric meter and point of use and therefore falls under section 36.351 and must offer the discount.

                In its rate-change application, Oncor proposed to continue providing the university

discount2 on the condition that it be allowed to subsidize the discount by recovering any resulting

revenue losses from all retail customer classes. In the alternative, it proposed to eliminate the

university discount in its entirety. State Agencies filed a motion for partial summary decision seeking

an order that Oncor be required to continue providing the discount and that it may not subsidize it.

The ALJs considered the State Agencies’ motion and recommended that it be granted, rejecting

Oncor’s argument that because it does not directly sell its transmission and distribution services to

state universities—but sells those services to REPs, who then sell the electricity to end-use retail

customers such as universities—it does not “provide electric service” to state universities and,

therefore, does not fall under the statute.




        2
         It is undisputed that, prior to deregulation, Oncor was required to provide the discount
and continued to provide the discount until this ratemaking proceeding.

                                                  10
               The Commission issued an order on the State Agencies’ motion rejecting the

ALJs’ recommendation, determining that—while Oncor had previously been required to provide

the discount before deregulation of the electric industry—Oncor was no longer required to provide

the discount because it is a transmission and distribution utility that operates in an area open to

competition, which “limits its provision of services to retail electric providers.” The Commission

concluded that “the 20% discount requirement [is limited] to integrated electric utilities that provide

electric service in areas that are not open to competition” and that the discount “does not apply to

services provided by a transmission and distribution utility that benefit [state universities] when the

service is provided to REPs in areas of the State that are open to competition.” Thus, concluded the

Commission, Oncor is no longer required to provide the discount. The Commission’s order on the

discount issue was incorporated into its final Order. State Agencies appealed the Order to the district

court, which reversed the Order, effectively reinstating the university discount.


Legislative and factual background of section 36.351

               Some background information on the origins of this statutory provision and the

regulation of electric utilities in Texas is useful. In 1975 the legislature enacted PURA, creating

the Commission and establishing a comprehensive regulatory regime for electric utilities. See

State v. Public Util. Comm’n, 110 S.W.3d 580, 583 (Tex. App.—Austin 2003, no pet.). Under the

regulated system, a single vertically integrated utility would provide all aspects of electric service

to retail customers: power generation, transmission and distribution, and the sale of electricity. Id.

Section 36.351 was enacted in 1995 prior to retail deregulation when utilities were still fully

regulated and vertically integrated. Id.

                                                  11
                Four years later, however, the Texas Legislature passed Senate Bill 7, amending the

Utilities Code “to establish competition in the retail market for electricity beginning January 1, 2002,

and ‘to protect the public interest during the transition’ to competition.” In re TXU Elec. Co.,

67 S.W.3d 130, 132 (Tex. 2001) (Phillips, C.J., concurring) (quoting PURA § 39.001(a)); see

Act of May 27, 1999, 76th Leg., R.S., ch. 405, 1999 Tex. Gen. Laws 2543, 2543-2625 (current

version at PURA § 39.001). The 1999 revisions to the Utilities Code were devised to “bring about

a major restructuring of the electric power industry in Texas to allow retail electric rates to be

determined by competition.” City of Corpus Christi v. Public Util. Comm’n, 51 S.W.3d 231, 235

(Tex. 2001). Senate Bill 7 amended PURA, partially deregulated the industry, and required each

utility to “unbundle” by January 1, 2002 into the following entities: a power generation company,

a transmission and distribution utility, and an REP. Public Util. Comm’n, 110 S.W.3d at 583.

                The power generation and retail markets would eventually be governed by

“customer choices and the normal forces of competition,” while the Commission would continue

to regulate transmission and distribution utilities. See PURA § 39.001(a). One of the effects of

unbundling was that, in areas open to competition, the newly created and unregulated REPs (rather

than vertically integrated “electric utilities”) became the entities with whom retail customers

contract for the provision and sale of electricity. The REPs incorporate the costs of transmission

and distribution services (those performed by Oncor and for which Oncor bills the REPs) and

the generation of electricity plus an amount to make a profit into a total electric bill that they then

charge to the retail customer. See id. § 39.107(d), (e) (after date of introduction of customer choice,




                                                  12
transmission and distribution utility “shall bill a customer’s retail electric provider for nonbypassable

delivery charges” and may only “bill retail customers at the request of a retail electric provider”).

                Under the new deregulated scheme and by design to develop a competitive market

for the provision of electricity, REPs’ rates are not regulated by the Commission. See id. § 39.001(a)

(“public interest in competitive electric markets requires that, except for transmission and

distribution services . . . , electric services and their prices should be determined by customer choices

and the normal forces of competition”). The rates of transmission and distribution utilities, on the

other hand, are clearly still regulated, evidenced by the necessity of this ratemaking proceeding.

The Commission contends that, with the deregulation of power generation and the sale of retail

electric service, now unbundled from the transmission and distribution functions, the meaning of

“providing electric service” to retail customers has changed.

                When enacting Senate Bill 7, the legislature recognized that a fully functioning

competitive electric market would not emerge instantaneously on January 1, 2002, but instead

would take time to develop, necessitating temporary measures to protect consumers while facilitating

the transition to competition. See CenterPoint Energy, Inc. v. Public Util. Comm’n, 143 S.W.3d 81,

96 (Tex. 2004) (“The Legislature recognized that . . . a market for electricity, both wholesale and

retail, would need time to develop, and there would be interim distortions and fluctuations, perhaps

even severe ones.”). One such measure was a temporary rate freeze or rate cap for state universities,

outlined in uncodified section 63 of the bill. See Act of May 27, 1999, 76th Leg., R.S., ch. 405, § 63,

1999 Tex. Gen. Laws 2543, 2625 (uncodified). Section 63 provided:




                                                   13
        Notwithstanding any other provision of this Act or Title 2, Utilities Code, any person
        or entity that provides electric service to a four-year state university, upper-level
        institution, Texas state technical college, or college, as provided by Section 36.351,
        Utilities Code, on December 31, 2001, shall continue to offer electric service to a
        four-year state university, upper-level institution, Texas state technical college, or
        college, as provided by Section 36.351, Utilities Code, until September 1, 2007,
        at a total rate that is no higher than the rate applicable to the university, institution,
        or college on December 31, 2001. The rate applicable to a four-year state university,
        upper-level institution, Texas state technical college, or college, as provided by
        Section 36.351, Utilities Code, on December 31, 2001, shall be based on the rates
        provided for or described in Section 36.351, Utilities Code. [ . . . ] As used in this
        section, “person or entity” includes an electric utility, affiliated retail electric
        provider, municipal corporation, cooperative corporation, or river authority.


Id. Section 63 extended the provisions of PURA section 36.351 to include the “newly-created

electric power providers that did not exist when § 36.351 was adopted in 1995,” for instance, REPs.

See Tex. Pub. Util. Comm’n, Application of Entergy Gulf States, Inc. for Auth. to Change Rates and

to Reconcile Fuel Costs, Docket No. 34800, 2008 WL 2852370, at *3-4 (July 16, 2008) (proposal

for decision on State’s motion for partial summary disposition). This Court noted that one of the

intentions of section 63 was to “preserve th[e] regulated twenty-percent discount for the state Colleges

. . . for a period of almost six years.” Public Util. Comm’n, 110 S.W.3d at 583. The Commission and

Oncor concede that section 36.351 is still in full force and effect but maintain that it applies only for

those utilities that have remained fully integrated and continue to operate in a non-competitive

market, not for Oncor and similarly situated transmission and distribution utilities in areas open to

customer choice.3


        3
          Notably, in Senate Bill 7 the legislature neither repealed nor amended section 36.351. The
inclusion in the bill of section 63 is supportive of appellants’ position: were the applicability of
section 36.351 intended to remain exactly as it was prior to Senate Bill 7 (that is, applying both
to vertically integrated and unbundled utilities operating in areas open to customer choice), there

                                                   14
Section 36.351 is ambiguous

               The parties do not dispute that before deregulation, when Oncor and its successor

power-generation company and REP were vertically integrated as one entity, Oncor provided

“electric service” (however the term is defined) to retail end-users, including state universities,

because the single entity handled every aspect of providing electricity to retail customers. However,

now that its operations have been unbundled, Oncor argues that it no longer provides electric service

to retail customers but provides only transmission and distribution services to REPs who then

provide electric service to retail end-users by selling them electricity. This assertion is consistent

with the fact that, since deregulation, Oncor is explicitly prohibited from “selling” electricity. PURA

§ 39.105(a) (“After January 1, 2002, a transmission and distribution utility may not sell electricity

or otherwise participate in the market for electricity except for the purpose of buying electricity to

serve its own needs.”).

               The term “electric service” is not defined in the Utilities Code. We conclude that the

term’s meaning in section 36.351, especially as it appears in the phrase “electric service provided

to [state universities],” is ambiguous because it could reasonably refer broadly to the provision of

any kind of service related to electricity (such as transmission and distribution) or narrowly to

only the provision of electricity to retail customers. Because we conclude the statute is ambiguous,




would have been no reason to include section 63. In other words, if section 36.351 already required
transmission and distribution utilities to provide the 20% discount indefinitely, the express
requirement in section 63 that an “electric utility,” which includes a transmission and distribution
utility, to continue to provide the discount until 2007 would have been superfluous. “[T]he
Legislature is never presumed to do a useless act.” Hunter v. Fort Worth Capital Corp., 620 S.W.2d
547, 551 (Tex. 1981).

                                                  15
we must consider whether the Commission’s interpretation is reasonable and, if so, defer to that

interpretation. See Texas Citizens, 336 S.W.3d at 625.


The Commission’s interpretation

                The Commission concluded that Oncor provides transmission and distribution

services to REPs in a competitive market but does not provide electric service to retail-customer

state universities as contemplated by section 36.351 because REPs now serve that function. We

conclude that this interpretation is reasonable and in harmony with the statute. Indeed, as this Court

has previously recognized, “[i]n the new competitive regime, a retail electric provider, as opposed

to an ‘electric utility,’ will provide electric service to State Colleges located in areas open to

competition.” Public Util. Comm’n, 110 S.W.3d at 585 (emphasis added).

                Although PURA does not define “electric service,” several provisions in the code

(which have been added since deregulation) use the term “electric service” in a way signifying that

it refers and is limited to the provision and sale of electricity to an end-use retail customer. For

instance, section 39.352, pertaining to the certification of an REP, requires the Commission to

issue a certification to a person who demonstrates “the financial and technical resources to provide

continuous and reliable electric service to customers in the area for which the certification is

sought.” PURA § 39.352(b)(1). Likewise, the term “customer choice” is defined as “the freedom

of a retail customer to purchase electric services . . . from the provider . . . of the customer’s choice.”

Id. § 31.002(4). Finally, section 17.202 specifically forbids an REP or “vertically integrated electric

utility in an area where customer choice has not been introduced” from disconnecting “electric

service” without sending a prescribed notice. Id. § 17.202. Notably, section 17.202 does not forbid

                                                    16
a transmission and distribution utility or a power generation company from disconnecting electric

service, presumably because neither of those entities actually provides “electric service” that would

be capable of being disconnected.

                A fundamental principle of statutory construction is that statutory terms should be

interpreted consistently in every part of an act. Texas Dep’t of Transp. v. Needham, 82 S.W.3d 314,

318 (Tex. 2002). Because the term “electric service” is consistently used throughout PURA to

signify the provision and sale of electricity to an end-use retail customer, it is reasonable to interpret

the use of that phrase in the university-discount section similarly. Because Oncor does not and

statutorily may not sell electricity to retail customers, it was reasonable for the Commission to

conclude that Oncor does not provide those customers with “electric service,” as the provision of

electric service to retail customers necessarily involves the sale of electricity, an activity in which

a transmission and distribution utility is expressly prohibited from engaging. See PURA §§ 39.352(a)

(only certified REP may provide retail electric service), .105(a) (transmission and distribution

utility may not sell electricity).

                Other provisions of the Utilities Code refer to the provision of “retail electric service”

(a term also not explicitly defined). It is undisputed that state universities are “retail customers”

who purchase electric service in the form of electricity. See PURA § 31.002(16) (“retail customer”

defined as “separately metered end-use customer who purchases and ultimately consumes electricity”);

see also id. § 17.002(4) (“customer” defined as person in whose name retail electric service is billed,

including governmental units at all levels of government). Section 17.002(6) defines an REP as a

“person that sells electric energy to retail customers in this state after the legislature authorizes a

customer to receive retail electric service from a person other than a certificated retail electric

                                                   17
utility.” Id. § 17.002(6). Similarly, section 39.352(a) prohibits a person from “provid[ing] retail

electric service” unless it is certified as an REP. Id. § 39.352(a). Because Oncor indisputably is not

an REP, the Commission argues, it may not provide “retail electric service” and sell electricity to

retail customers (including universities).

               In light of the Commission’s expertise and PURA’s use of the term “electric

service,” we find the Commission’s conclusion that Oncor provides transmission and distribution

services to REPs in a competitive market but does not provide electric service to state universities

as contemplated by section 36.351 to be reasonable and in harmony with the statute. The

Commission’s Order on this issue promotes a competitive, as compared to regulatory, approach to

establishing charges for the provision of electricity, which policy is consistent with the legislative

purposes since the introduction of customer choice.4 See PURA § 39.001(a), (d). Accordingly,

we defer to the Commission’s reasonable interpretation and reverse the district court’s judgment

reversing the Commission’s Order on the university-discount issue.


II.    Rate-base issues


A.     Oncor’s investment in automated meters


The dispute and the “prudence standard”

               Appellants Steering Committee and the Alliance challenge the Commission’s decision

allowing Oncor to include in its rate base the approximate $93 million it invested in its allegedly


       4
          We also find significant the Commission’s assertion that, because it has no authority to
regulate REPs’ rates, any discount it might require Oncor to provide to state universities would not
necessarily be passed along to the customer state universities.

                                                 18
imprudent purchase and deployment of automated-metering systems. Appellants assert that the

Commission’s decision (1) is not supported by substantial evidence and (2) is erroneous because the

Commission improperly applied its “prudence standard.”5

                “A utility has the burden to prove the prudence and reasonableness of its expenditures

before a rate increase can be approved.” Coalition of Cities for Affordable Util. Rates v. Public Util.

Comm’n, 798 S.W.2d 560, 563 (Tex. 1990), cert. denied, 499 U.S. 983 (1991). To raise the price

of its product, the utility must participate in a rate case and bear the burden of proving that each

dollar of cost incurred was reasonably and prudently invested. Entergy Gulf States, Inc. v. Public

Util. Comm’n, 112 S.W.3d 208, 214 (Tex. App.—Austin 2003, pet. denied) (citing Public Util.

Comm’n v. Houston Lighting & Power Co., 778 S.W.2d 195, 198 (Tex. App.—Austin 1989, no

writ)). A utility enjoys no presumption that its expenditures have been prudently incurred by simply

opening its books to inspection. Id.

                In its Order, the Commission acknowledged the application of its “prudence standard”

in reviewing the reasonableness of a utility’s investments as set forth in a prior case. See Gulf States

Utils. Co. v. Public Util. Comm’n, 841 S.W.2d 459, 475 (Tex. App.—Austin 1992, writ denied).

That standard defines prudence as “[t]he exercise of that judgment and the choosing of that select

range of options which a reasonable utility manager would exercise or choose in the same or similar




       5
           Steering Committee also asserts that the Commission’s decision was unreasonable and
arbitrary because Oncor’s purchase of some of the automated meters allegedly directly benefitted a
venture partner of its parent company, which constituted a conflict of interest. The ALJs found no
evidentiary support for Steering Committee’s claim of impropriety in the purchase of the meters,
and after our review of the record, we find that substantial evidence supports the Commission’s
finding of no impropriety.

                                                  19
circumstances given the information or alternatives at the point in time such judgment is exercised

or option is chosen.” Id. There may be more than one prudent option within the range available to

a utility in any given context, and any choice within the select range of reasonable options is

considered prudent. Nucor Steel v. Public Util. Comm’n, 26 S.W.3d 742, 752 (Tex. App.—Austin

2000, pet. denied). The reasonableness of an action or decision must be judged in light of the

circumstances, information, and available options existing at the time, without benefit of hindsight.

Id. The Commission should not substitute its judgment for that of the utility. Id.

               Appellants do not challenge the applicability of this standard but contend that

the Commission made an error of law by applying it incorrectly when it considered evidence of

events that occurred after Oncor had already purchased the meters at issue. Appellants also assert

that at some point in Oncor’s multi-year purchase and deployment of automated meters, Oncor

knew or should have known that the meters it was deploying might not meet the functionality

requirements of new rules that the Commission was in the process of promulgating. At that point

in time, appellants contend, Oncor should have ceased purchasing and deploying the automated

meters until the Commission issued its final rules, providing guidance on which types of meters

would meet the guidelines.

               The ALJs determined that Oncor had acted imprudently in continuing to purchase

and deploy its automated meters after December 2005 when the Commission requested public

comments on its rulemaking addressing “advanced metering,” specifically seeking comments about

whether advanced-metering technologies should be standardized or left to utilities’ own decisions.6


       6
        Importantly, and as discussed infra, these rulemaking proceedings pertained to the
promulgation of requirements by which utilities’ voluntary deployment of advanced-metering

                                                 20
In its Order, the Commission rejected the ALJs’ proposal recommending disallowance of Oncor’s

automated meter expenses incurred after December 2005 and instead permitted Oncor to recover

the full costs of its automated meters. Some of the evidence that the Commission cited in support

of its determination that Oncor’s deployment of the meters had been prudent involved comments

made at Commission meetings in May 2007, well after Oncor had already purchased the meters at

issue. The comments allegedly “encouraged” Oncor to continue deploying the meters despite the

imminent finalization of the Commission’s rule outlining functionalities that Oncor’s meters

allegedly did not have.

                We must uphold the Commission’s decision if there is “some reasonable basis” for

it in the record. El Paso, 883 S.W.2d at 185. This is so even if the evidence preponderates against

the decision. Id.


Evidence supporting Oncor’s prudence

                Evidence showed that beginning in December 2004, Oncor began an initiative to

replace its existing conventional meters with automated meters in response to a trend across the

electric utility industry that had been occurring for at least 20 years. Other utilities across the country

had been deploying substantial numbers of automated meters for more than a decade. Oncor

executives testified that its decision to replace its conventional meters was part of its larger “Smart

Grid” initiative encompassing several components besides automating its metering infrastructure,

such as automation of distribution and transmission and implementation of advanced communications



systems would entitle the utilities to recover associated costs through a rate surcharge. See PURA
§ 39.107(h).

                                                    21
and information management. The intentions behind these advanced technologies allegedly included

improved reliability, increased customer satisfaction, and improved future services to consumers.

The enhanced communications abilities of Smart Grid technologies include the ability to read

meters remotely and in real time, predict network problems before they affect customers, detect

outages and other network problems as they occur, and speed the restoration and repair of an electric

utility’s system. As Oncor witnesses testified, the industry had already been moving in the direction

of Smart Grids when Oncor—seeking to remain a top performer in providing safe, reliable electric

delivery service to end-use consumers—decided to implement its initiative.

               In mid-2004 as it rolled out its Smart Grid initiative, Oncor issued a request for

proposals to a large number of vendors seeking input on the types of meters that it might deploy.

In considering the various proposals and meters then on the market, Oncor found that no single

vendor or technology met all of its requirements for the deployment of a uniform automated-

metering system for all of its end-use customers. Therefore, Oncor chose to deploy a combination

of automated meters and technologies, ultimately settling on two types: two-way Power Line Carrier

(two-way line) and Broadband over Power Line (broadband line) systems. Its choice to deploy two

different technologies was an attempt to meet the various needs of its diverse customer base.

               Besides the industry trend, evidence showed that both state and federal legislation

encouraged Oncor to invest in automated meters. The Texas Legislature passed House Bill 2129 in

May 2005 encouraging the adoption of automated meters, stating that an automated-metering system

has “the potential to increase the reliability of the regional electrical network, encourage dynamic

pricing and demand response, make better use of generation assets and transmission assets,

and provide more choices for consumers.” Act of May 29, 2005, 79th Leg., R.S., ch. 1095, § 8,

                                                 22
2005 Tex. Gen. Laws 3615, 3618 (uncodified). That same year, the legislature also passed Senate

Bill 5, in which it found that broadband line meters can be used “to enhance existing electric delivery

systems, which can result in improved service and reliability for electric customers.” Act of Aug.

10, 2005, 79th Leg., 2d C.S., ch. 2, §§ 1-32, 2005 Tex. Gen. Laws 4, 4-34 (current version at PURA

§43.001). Additionally, in enacting the Energy Policy Act, the U.S. Congress expressed its desire for

utilities to deploy advanced-transmission technologies. See Energy Policy Act of 2005, Pub. L. No.

109-158, 119 Stat. 594 (codified in scattered sections of 42 U.S.C.); 42 U.S.C. § 16422 (2005)

(Federal Energy Regulatory Commission “shall encourage, as appropriate, the deployment of

advanced transmission technologies”). Oncor witness Ken Carpenter testified that these pieces of

legislation supported Oncor’s actions in deploying its Smart Grid technology.

               House Bill 2129 also amended PURA section 39.107(h) to allow for an alternative

mechanism for utilities to recover reasonable and necessary expenses incurred in connection with

deployment of advanced meters short of full-scale ratemaking proceedings by directing the

Commission to establish requirements for the recovery of a nonbypassable surcharge. See PURA

§ 39.107(h). The amendment did not specify functionality requirements for meters that would

become eligible for the surcharge but, rather, left the task of defining “advanced metering and

meter information networks” to the Commission’s rulemaking function. See id. Notably, section

39.107(h) did not require utilities to deploy advanced-metering systems (AMS) or prohibit them

from continuing to recover investment in other kinds of meters through ratemaking proceedings

rather than a surcharge. See id.; see also 16 Tex. Admin. Code § 25.130(d)(1) (2014) (Pub. Util.

Comm’n of Tex., Advanced Metering) (“Deployment and use of AMS by an electric utility is

voluntary unless otherwise ordered by the commission.”).

                                                  23
               At the first rulemaking workshop on the AMS surcharge, held in September 2005,

various advanced-metering technologies were discussed, and a presentation was given by a vendor

of Smart Grid technologies wherein the very capabilities of the broadband line and two-way line

meters Oncor was deploying and continued to deploy were described as constituting then-available

“advanced” automated metering.7 Part of that presentation also included a study revealing that from

1996 to 2005, several large and well-known utilities across the country had deployed significant

numbers of automated meters, including one that had installed over 2 million of them in 2002 and

one that had deployed over 600,000 in 2004. The meters that these utilities deployed did not have

the advanced functionality later identified in the Commission’s final rule 25.130 because, as an

Oncor witness testified, even as late as when the surcharge rule became effective in May of 2007,

there was no commercially available residential meter in the country that could meet all of the

functionality requirements of the new rule. See 16 Tex. Admin. Code § 25.130. According to

Commission witness Kevin Mathis, broadband line and two-way line meters provided “significant

advantage” over conventional meters.

               Oncor placed its first order of approximately 265,000 automated meters for which it

sought recovery in this case in May 2005. Over the course of the next two years, Oncor made several

more orders, ultimately purchasing approximately 600,000 automated two-way line and broadband

line meters for which it sought and was granted recovery by the Commission. However, because


       7
          In this opinion, the term “automated meters” refers to meters such as the two-way line
and broadband line meters Oncor deployed that, while more advanced than conventional electro-
mechanical meters, do not have all the functionality required to qualify for the Advanced Meter
System (AMS) surcharge under the Commission’s substantive rule 25.130. See 16 Tex. Admin.
Code § 25.130 (2014) (Pub. Util. Comm’n of Tex., Advanced Metering). AMS-qualified meters are
herein referred to as “advanced meters.”

                                                24
Oncor made most of its decisions to purchase and deploy the two-way line and broadband

line meters while the surcharge rulemaking proceedings were ongoing and “advanced meter

functionality” was not yet defined, appellants argue that Oncor was imprudent in continuing to

purchase and deploy meters without knowing whether they would qualify for the surcharge.

               Our review of the record indicates that there is a reasonable basis and more than a

scintilla of evidence to support the Commission’s determination that Oncor’s decisions about

purchasing and deploying its two-way line and broadband line meters—even in the midst of

rulemaking proceedings promulgating eligibility requirements for voluntary participation in a

surcharge scheme—were within the “range of options which a reasonable utility manager would

exercise or choose in the same or similar circumstances given the information or alternatives at the

point in time such judgment is exercised or option is chosen.” See Nucor Steel, 26 S.W.3d at 752.

The Commission could reasonably have determined that the promulgation of rules pertaining to

the voluntary deployment of advanced meters had little to no bearing on the prudence of Oncor’s

decisions, especially considering the benefits that the automated meters provided, Oncor’s

Smart Grid initiative, legislative directives to deploy such meters, industry trends, and available

technology.8 We may not substitute our judgment for that of the Commission on the factual

determination of Oncor’s prudence, and we hold that the above-cited evidence amounts to more




       8
         Also, the inclusion in the Commission’s final rule of a “grandfather” provision allowing
a surcharge for broadband line meters such as those deployed by Oncor is indicative of its policy
determination that a utility’s purchase and deployment of such meters—even during the rulemaking
process—was not per se imprudent but, in fact, prudent enough to entitle those “non-compliant”
meters to recovery through a surcharge. See 16 Tex. Admin. Code § 25.130(g)(1)(c) (2014) (Pub.
Util. Comm’n of Tex., Advanced Metering).

                                                25
than a scintilla to support the Commission’s prudence determination.9 See El Paso, 883 S.W.2d at 185

(substantial evidence is more than scintilla, and record evidence may preponderate against agency

decision and nonetheless amount to substantial evidence).


Alleged improper application of “prudence standard” by the Commission

               Although appellants do not challenge the Commission’s use of the above-cited

prudence standard, they argue that the Commission committed legal error by improperly applying

that standard to the facts in this case. Specifically, they argue that the Commission considered

irrelevant evidence in determining Oncor’s prudence. They note the Commission’s Order citing

evidence that on May 8, 2007—well after Oncor had purchased all of the meters at issue and just

before the Commission’s advanced-metering rule was finalized—the Commission held an open

meeting during which the Commissioners present “strongly encouraged [Oncor’s] deployment of

[broadband line] meters.”

               Appellants rightfully argue that this and other evidence of “encouragement” by the

Commission to Oncor to continue deploying its automated meters is not relevant to the determination




       9
           Appellants point to Oncor’s later decision to replace and seek a surcharge for the very
broadband line and two-way line meters that it had recently deployed, allegedly before the end of
the automated meters’ useful lives, as further evidence of imprudence. However, Oncor’s AMS
Deployment Plan (and the Commission’s approval thereof) is not before us on review, and even if
its later AMS Deployment Plan were relevant to the prudence of its earlier decisions to deploy the
automated meters, there is nonetheless substantial evidence supporting the Commission’s decision.
Also, the Commission’s final AMS rule imposes no time-in-service requirement on meters that
are to be replaced and, in fact, specifically provides for the recovery in a base-rate proceeding that
occurs while a surcharge is in effect “of any non-AMS metering equipment that has not been fully
depreciated but has been replaced by the equipment installed under an approved Deployment Plan.”
See id. § 25.130(k)(4) (2014) (Pub. Util. Comm’n of Tex., Advanced Metering).

                                                 26
of Oncor’s prudence at the much earlier times when the decisions to purchase the meters were

made. We agree that the prudence standard requires consideration of the circumstances at the time

that the particular decision at issue is made, and Oncor may not meet its burden of proof on the

prudence issue by relying on events occurring later in time. However, any weight that the Commission

gave to this irrelevant evidence does not render its application of the prudence standard legal error,

as long as there is substantial, relevant evidence to support its determination. Because we have

determined that there is—even disregarding evidence of the Commission’s later encouragement to

Oncor to continue to deploy the automated meters—we conclude that the Commission’s application

of its prudence standard did not constitute legal error. The Commission’s decision on the inclusion

of Oncor’s automated-metering investments in its rate base is supported by substantial evidence and

is not arbitrary and capricious or affected by other error of law. Accordingly, we overrule Steering

Committee’s and Alliance’s respective second issues.


B.     Calculation of lead days for franchise-tax component of cash working capital

               Oncor’s third issue challenges the Commission’s Finding of Fact Number 70A

concerning the calculation of a component of its cash-working-capital allowance. Specifically,

Oncor asserts that the Commission’s calculation of the number of “lead days” related to the state

franchise tax as a component of its cash-working-capital allowance was erroneous because it relied

on an incorrect construction of the applicable statutes. The Commission responds that the calculation

was subject to the Commission’s discretion rather than prescribed by statute and that substantial

evidence supports its calculation.




                                                 27
               While not explicitly mandated by PURA, the Commission’s rules permit a utility

to maintain a cash-working-capital allowance as a component of its rate base. 16 Tex. Admin. Code

§ 25.231(c)(2)(B)(iii) (2014) (Pub. Util. Comm’n of Tex., Cost of Service). This allowance is

designed to address the inherent delay that exists between the time that a utility pays for costs

associated with providing its service and the time that the utility receives revenues from ratepayers

to recover those costs. A cash-working-capital allowance comprises the operating funds, not

specifically addressed in other rate-base items, that are necessary to fund the gap between the time

that expenditures are made and the time that corresponding revenues are received.

               To calculate the cash-working-capital allowance, the Commission utilizes a

“lead-lag study.” Id. § 25.231(c)(2)(B)(iii)(IV). Although not defined in the Utilities Code or the

Commission’s regulations, the parties are in agreement about what a lead-lag study measures:

the difference between (1) the time between the date when the ratepayer receives service from the

utility and the date on which the ratepayer pays for the service provided (the “revenue lag”) and

(2) the time between the date that a utility’s costs are incurred (or when the utility receives goods

or services from a third party) and the date that those expenses are paid (the “expense lead”). Any

difference in these time periods is expressed in days. The cash-working-capital allowance is then

calculated by multiplying those days by the average daily operating level for a particular category

of expense. Generally, increases in revenue-lag days and decreases in expense-lead days result in

increases to the amount of cash working capital included in the rate base, while decreases to

revenue lag days and increases in expense-lead days result in decreases to the cash working




                                                 28
capital included in rate base. Consequently, the lead-lag study can result in either an addition to

or a reduction of the rate base depending on the utility’s cash requirements.

               On appeal, Oncor challenges the Commission’s calculation of Oncor’s lead-day figure

for one particular category of expense: the Texas franchise tax, which is a “tax on the privilege of

doing business in Texas.” TGS-NOPEC Geophysical Co. v. Combs, 340 S.W.3d 432, 437 (Tex.

2011); see Tex. Tax Code § 171.001 (“A franchise tax is imposed on each taxable entity that

does business in this state.”). Before 2008, the franchise tax was assessed on an entity’s capital or

earned surplus; beginning January 1, 2008, the tax was assessed on an entity’s “taxable margin.”

TGS, 340 S.W.3d at 437; see Tex. Tax Code §§ 171.002 (tax rate is either 1% or 0.5% of taxable

margin), .101 (defining “taxable margin”). Notably, the switch to assessing the tax on “taxable

margin” rather than on capital or earned surplus began on January 1, 2008, the day after Oncor’s test

year ended. However, besides the way that the tax was calculated and amendments not relevant to

this dispute, the other relevant provisions of the franchise-tax scheme did not substantively change

in 2008 (for instance, the due dates for payment of the tax and privilege periods covered by the tax

have remained consistent).10

               Oncor argues that the Commission erred in calculating the lead days for its franchise-

tax payment at negative 319.58 days instead of the positive 46.42 days that Oncor requested. While




       10
           The parties throughout the ratemaking proceeding and on appeal have referred to the
franchise tax as the “gross margin tax” because it is now assessed on the basis of taxable margins.
However, the Tax Code and relevant case law still use the term “franchise tax.” To maintain
consistency with these authorities, we will use the term “franchise tax” when referring to the tax
generally but will use the term “margin tax” when the change in how the tax is assessed is relevant
to the discussion.

                                                 29
no statute or regulation prescribes how lead days are to be calculated, the parties are in agreement

that the formula testified to by Commission staff witness Mary Jacobs controls: lead days are

computed by taking the difference between the date that a utility’s costs are incurred and the date

that they are paid. The dispute between the parties centers around the determination of when

Oncor’s franchise-tax expense for the 2008 calendar year was “incurred”—specifically, whether it

was incurred in 2007 or 2008. Oncor argues that it did not incur the margin tax until 2008 when

the new tax scheme became effective and when its first payment thereunder was due and actually

paid. The Commission maintains that Oncor incurred the margin tax when it recorded the expense

on its accounting books in 2007.

               Oncor’s witness David Sigler explained why the utility recorded the 2008 franchise-

tax expense on its 2007 books: such accounting method was allegedly required by GAAP (Generally

Accepted Accounting Principles) because the amended franchise tax had “been interpreted to be an

income tax for accounting purposes and therefore will not be reported in the same manner as the

[prior] franchise tax.”11 According to Sigler, this change in accounting practices resulted in Oncor’s

doubly recording on its 2007 books both its actual franchise-tax liability for 2007 and a hypothetical

margin-tax liability, even though Oncor would not be subject to computing its tax liability on

the basis of taxable margins until 2008. Then, as Oncor witness Alan Ledbetter explained, Oncor

removed the actual 2007 franchise-tax expense from its rate-filing package and replaced it with

the hypothetical margin-tax calculation to account for the “known and measurable change” in the


       11
           But see In re Allcat Claims Serv., L.P., 356 S.W.3d 455, 463 (Tex. 2011) (noting
legislature’s express statement in amending Act that “franchise tax imposed by Chapter 171, Tax
Code, as amended by this Act, is not an income tax”).

                                                 30
tax laws going forward. See 16 Tex. Admin. Code § 25.231(b) (2014) (Pub. Util. Comm’n of Tex.,

Cost of Service) (“In computing an electric utility’s allowable expenses, only the electric utility’s

historical test year expenses as adjusted for known and measurable changes will be considered.”).

Thus, the hypothetical dates that Ledbetter used for calculating expense-lead days were May 15,

2007 (when the margin tax covering the year 2007 would have been due and paid) and approximately

July 1, 2007 (the midpoint of the “privilege period” or year that the tax payment would have

covered).12 The Commission used the same “incurred” date as Oncor, not because it understood the

margin tax to have actually or hypothetically been assessed on that date, but solely because that is

when Oncor recorded the liability on its books (for the reasons explained by Ledbetter and Sigler).

Then the Commission used a tax “paid” date of the following calendar year—May 15, 2008—when

Oncor in fact made its first franchise-tax payment under the new margin-tax scheme.

               Oncor contends that its accounting system is irrelevant to the determination of when

it legally incurred the franchise-tax expense and that for the purposes of a lead-lag study a taxable

entity “incurs” the tax in the year when payment of the tax covering that year is due. In other words,


       12
           Oncor’s work papers supporting its rate-change application provide the specifics of a
more detailed calculation than merely taking the mid-point of the calendar year, which explains why
the parties’ respective lead-day figures contain fractional days. Essentially, Oncor first computes
the difference between the mid-point of each month during the annual period covered by the
franchise tax and the payment date to find a lead-day figure for each month. Next, it averages each
of these monthly figures to compute the final lead-day figure for the year. However, the year mid-
point (July 1) is a close approximation to the “incurred” date resulting from Oncor’s calculation, as
noted in its appellate briefs. Because the Commission used the same methodology as Oncor in
computing the incurred date and only disagreed with respect to which year they were incurred—i.e.,
whether they were incurred the year that they were paid or the year prior—we use the July 1 date in
our discussion for simplicity’s sake. We also note that because the two dates advanced by Oncor
have the year in common, Oncor could have arrived at the same lead-day figure had it used the
corresponding two dates of calendar year 2008 when the margin-tax scheme became effective.

                                                 31
the lead days should have been calculated by taking the difference between July 1 and May 15 of the

same year, not between July 1 of one year and May 15 of the next year, because the tax covers the

“privilege period” constituting the year when the tax payment and required annual report are due.

See 34 Tex. Admin. Code § 3.584(c)(1)(C)(ii) (2014) (Comptroller of Pub. Accounts, Margin:

Reports and Payments) (“The annual franchise tax report must be filed and the tax paid no later than

May 15 of each year. . . . The privilege period for an annual report is January 1 through December 31

of the year in which the annual report is originally due.”). Oncor submits that the determination of

when an entity incurs the franchise-tax liability is a question of law, which we must review de novo.

The Commission responds that this is not a question of law because no statute or regulation

specifically addresses how to calculate the lead time and that, therefore, the resolution of the issue

was within its discretion, subject only to substantial-evidence review.

               We agree with Oncor that this issue raises a question of law. Its resolution requires

a determination of whether, under the applicable statutes, the franchise tax is paid to provide a

privilege for the calendar year in which the tax is actually paid or for the previous calendar year

and, similarly, when a taxable entity legally incurs liability for the tax. Although the Commission

is correct that no statute or regulation prescribes exactly how to calculate the lead days, under the

Commission’s own formula (as testified to by its witness Jacobs), the calculation necessarily

depends on the determination of when a utility “incurs” liability for the franchise tax. Thus, we turn

to consideration of the statutes imposing the franchise tax.

               The Tax Code specifically provides that a franchise-tax payment assessed on the

privilege of conducting business in Texas for a particular year is due on May 15 of that same year:

                                                 32
“Payment of the tax covering the regular annual period is due May 15, of each year after the

beginning of the regular annual period.” Tex. Tax Code § 171.152(c) (emphasis added); see also

Universal Frozen Foods Co. v. Rylander, 78 S.W.3d 588, 590 (Tex. App.—Austin 2002, no pet.)

(franchise tax is levied for privilege of doing business in Texas during year for which tax is paid);

General Dynamics Corp. v. Sharp, 919 S.W.2d 861, 866 (Tex. App.—Austin 1996, writ denied)

(franchise tax is “prospective because the tax levied beginning January of a given calendar year pays

for the privilege of doing business through December of that calendar year”). The plain language

of section 171.152(c) indicates that payment made on May 15 of each year covers the privilege of

conducting business in Texas for that year, not the prior year.13 It then follows that the tax is

“incurred” in the calendar year when payment is due.

               The ordinary definition of the word “incur” supports this construction. Incur means

“to become liable or subject to,” Webster’s Third New Int’l Dictionary 1146 (2002), and “to suffer

or bring on oneself (a liability or expense),” Black’s Law Dictionary 836 (9th ed. 2009). Similarly,

a liability is a “quality or state of being legally obligated or accountable.” Id. at 997. A taxable

entity becomes liable for the Texas franchise tax on the date that it first conducts business in the

state and then, after the start of a “regular annual period,” on every January 1 thereafter. See Tex.

Tax Code §§ 171.151, .152; see also General Dynamics, 919 S.W.2d at 866.


       13
           This is true even though computation of the amount of that tax is based on taxable
margins of the prior year. See Tex. Tax Code § 171.1532 (tax “covering the regular annual period”
is based on federal income tax returns of year prior to when report is due); see also 34 Tex. Admin.
Code § 3.587(d) (2014) (Comptroller of Pub. Accounts, Margin: Total Revenue) (same); Universal
Frozen Foods Co. v. Rylander, 78 S.W.3d 588, 590 (Tex. App.—Austin 2002, no pet.) (amount
owed for franchise tax is measured by financial performance during previous year).

                                                 33
                We also note that, despite its position in this case, the Commission has agreed with

this construction in a recent docket, specifically rejecting the very assertion that it advances here

that a utility’s accounting accrual of the tax expense determines when it incurs the expense. See Tex.

Pub. Util. Comm’n, Application of CenterPoint Elec. Delivery Co., LLC for Auth. to Change Rates,

Docket No. 38339, 2010 WL 5004444, at *10-12 (Dec. 2, 2010) (PFD) and 2011 WL 1960201,

at *9) (May 12, 2011) (order) (PFD citing Comptroller’s recent opinion in support of conclusion that

franchise tax “is paid for the privilege period of the calendar year in which the payment is made and

the report is due, regardless of when the accounting accrual for the cost occurs” and “franchise tax

payment is made on May 15 of any given year and relates to the service provided during the calendar

year”) (order approving franchise-tax conclusions of PFD).

                We agree with Oncor’s assertion that its recording of the franchise-tax liability on its

accounting books is not dispositive of the legal issue of when it in fact incurred that liability for the

purposes of a lead-lag study. Rather, the applicable Tax Code provisions prescribe when the

franchise tax is levied by the state and, consequently, incurred by a taxable entity. Oncor could not

have incurred the franchise-tax expense in the year prior to when the tax was assessed and for which

the tax provided the privilege of conducting business in Texas. The Commission’s determination

that Oncor incurred liability in 2007 for the franchise tax covering calendar year 2008 and its

calculation of Oncor’s lead days in accordance therewith was legal error. See Tex. Gov’t Code

§ 2001.174(2)(D). Accordingly, we reverse the portion of the Commission’s Order setting Oncor’s

expense-lead days for the franchise-tax component of cash working capital (Finding of Fact 70A)



                                                   34
and remand the issue to the Commission for recalculation of Oncor’s cash-working-capital allowance

for the state franchise tax in accordance with this opinion.


C.      Issues related to Oncor’s accumulated deferred federal income tax (ADFIT)


1.      Overview of ADFIT accounting practices

                Expenses related to federal income taxes for ratemaking purposes are “normalized,”

which means that the Commission must balance equitably the interests of present and future

ratepayers and apportion between consumers and the utility certain tax benefits resulting from

depreciation and amortization, investment tax credits, and similar applications. See PURA § 36.059;

16 Tex. Admin. Code § 25.231(b)(1)(D). For instance, for depreciation expenses, rates are set as

if depreciation is paid on a “straight line” basis, even though for tax purposes accelerated depreciation

allows the utility larger tax deductions in the early years of an asset’s life. Office of Pub. Util. Counsel

v. Public Util. Comm’n, 303 S.W.3d 904, 912 (Tex. App.—Austin 2010, no pet.). The excess amount

of money collected from ratepayers for taxes that are not immediately paid to the Internal Revenue

Service (IRS) is referred to as the accumulated deferred federal income tax (ADFIT) “account

balance.” Id.

                Eventually, the ADFIT account balance is used to pay future federal income taxes,

but in the meantime, the utility essentially has access to cost-free capital or a “loan” from ratepayers.

See American Elec. Power Co. v. Public Util. Comm’n, 123 S.W.3d 33, 38 (Tex. App.—Austin

2003, no pet.). Because of the utility’s access to cost-free capital, the applicable rules require the

utility’s ADFIT account balance to be deducted from its rate base so that the utility does not earn a



                                                    35
return on that capital. See 16 Tex. Admin. Code § 25.231(c)(2)(C)(I) (rate base must be reduced by

accumulated reserve for deferred federal income taxes). Essentially, if the utility’s shareholders have

not provided an asset—which is the case with ADFIT because the capital has been provided by the

taxpayers and the federal government—then they are due no return on it.

               Besides accounting for depreciation and other so-called ADFIT “liabilities,” ADFIT

account balances also provide for so-called ADFIT “assets,” such as pension plans, which for

tax and accounting purposes operate essentially the opposite of ADFIT liabilities. For instance,

with pensions, the utility records an expense on its regulatory books before it is entitled to the

corresponding tax deduction, which will occur upon future payment of the employee benefit.

Together, the ADFIT assets and liabilities compose the ADFIT account balance. Assets decrease

that balance and liabilities increase it, and the total ADFIT account balance is then deducted from

the rate base. ADFIT assets therefore operate to increase the rate base while ADFIT liabilities

operate to reduce it.

               Two issues in this appeal relate to the Commission’s treatment of Oncor’s ADFIT

account balance. The first involves the Commission’s decision about a new accounting standard by

which Oncor sought to reduce its ADFIT account balance; the second involves the inclusion of

expenses for pensions and other post-employment benefits in Oncor’s ADFIT balance. We will

address each in turn.


2.     Financial Interpretation 48 (FIN 48)

               In its second issue on appeal, Oncor asserts that the Commission acted arbitrarily and

capriciously in not allowing certain deductions from its ADFIT balance, when such deductions were

                                                  36
purportedly required by a financial interpretation recently issued by the Financial Accounting

Standards Board (FASB). The Commission and other appellees14 respond that substantial evidence

supports the Commission’s findings and conclusions rejecting Oncor’s request and that its

determination was reasonable and a proper exercise of its discretion.

                    The FASB establishes financial accounting and reporting standards for companies

in the United States and recently examined how companies were reporting “uncertain tax

positions” on their financial statements. In June 2006, the FASB issued Financial Interpretation

Number 48 (FIN 48), which provides guidance for the treatment of “uncertain tax positions.”

See Accounting for Uncertainty in Income Taxes, Statement of Fin. Accounting Standards No. 48

(Fin. Accounting Standards Bd. 2006) (FIN 48). “Uncertain tax positions” are those positions

(e.g., tax deductions) a company takes on its income-tax return that, given “the complexities

and varying interpretations of the tax law, . . . may not ultimately prevail” if the IRS audits the

return.        American Institute of Certified Public Accountants, Practice Guide on Accounting

for Uncertain Tax Positions Under FIN 48, at 3 (Nov. 29, 2006), available at

http://www.franke.nau.edu/facstaff/kilpatrick-b/ACC570/Readings/AICPA%20FIN48.pdf (FIN 48

Practice Guide). FIN 48 became effective for fiscal years beginning after December 15, 2006, and

applies to all entities subject to GAAP.15 See FIN 48 Practice Guide at 3, 7. If a tax position is

“uncertain,” the entity will more likely than not have to pay the IRS additional federal income-tax

amounts attributable to that position if audited. See id. at 4.

          14
                Besides the Commission, the OPUC and TIEC filed appellee’s briefs in opposition to
this issue.
          15
               The parties do not dispute that Oncor is subject to GAAP.

                                                   37
               FIN 48 prescribes a two-step analysis for each uncertain tax position an entity takes,

requiring it to determine first whether each position is more likely than not to be upheld by the IRS

and, for those positions meeting the more-likely-than-not threshold, whether the positions represent

benefits that will be accounted for in the entity’s financial statements. FIN 48 at 11. Following

these steps, Oncor adjusted its financial statements by reclassifying those tax benefits that its tax

professionals believed reflected uncertain tax positions that were unlikely to succeed, removing

those benefits from its ADFIT account balance and establishing a non-current reserve with those

items and accruing interest on them. The amount Oncor removed from its ADFIT account balance

was $96,972,460, which increased its rate base by the same amount. This increase in its rate base

would have resulted in Oncor recovering an additional $8 million in annual rates due to the

Commission’s approved rate of return on Oncor’s invested capital of 8.28%. Accepting the

recommendation of the ALJs, the Commission prohibited Oncor’s removal of these uncertain tax

positions from its ADFIT account balance, determining that FIN 48 does not affect how the utility

must account for ADFIT benefits for ratemaking purposes, and Oncor appeals that decision.

               No statute or regulation requires the Commission to follow the guidance in FIN 48

for ratemaking purposes or to accordingly remove uncertain-tax-position amounts from a utility’s

ADFIT account balance. PURA provides general guidance to the Commission for the treatment of

tax savings resulting from accelerated depreciation and amortization, and the Commission’s rules

require the Commission to deduct the ADFIT account balance from the rate base, but the details of

the ADFIT calculation are left to the Commission’s discretion. See PURA § 36.059(a); 16 Tex.

Admin. Code § 25.231(c)(2)(C)(I). Relevant to the ADFIT calculation is the Commission’s mandate



                                                 38
that utilities use the accounting methods adopted by the Federal Energy Regulatory Commission

(FERC) in their regulatory accounting and ratemaking proceedings. See 16 Tex. Admin. Code §

25.72(c) (2014) (Pub. Util. Comm’n of Tex., Uniform System of Accounts) (“each electric utility

. . . shall maintain its books and records in accordance with the . . . uniform system of accounts as

adopted and amended by the Federal Energy Regulatory Commission (FERC)”).

               Commission staff witnesses testified against the advisability of changing long-

standing Commission policy requiring the inclusion in the ADFIT account balance of all tax

deductions taken by a utility in its tax return. They testified that the FIN 48 requirements do not

apply to ratemaking proceedings but only to financial accounting in the preparation of reports for

use in the private sector, and they agreed with the FERC’s stated concern that FIN 48 “frustrates”

the measurement objective of its uniform systems of accounts. Staff witness Candice Romines

cited a FERC guidance letter noting that the FERC’s recommended practice in place prior to FIN 48


       results in the accumulated deferred income tax accounts reflecting an accurate
       measurement of the cash available to the entity as a result of temporary differences
       [and that t]his is an important measurement objective of the Commission’s Uniform
       Systems of Account because accumulated deferred income tax balances, which are
       significant in amount for most Commission jurisdictional entities, reduce the base on
       which cost-based, rate-regulated entities are permitted to earn a return. FIN 48,
       which does not permit a liability for uncertain tax positions related to temporary
       differences to be classified as a deferred tax liability, frustrates this important
       measurement objective. Therefore, entities should continue to recognize deferred
       income taxes for Commission accounting and reporting purposes based on the
       difference between positions taken in tax returns filed or expected to be filed and
       amounts reported in the financial statements.


Accounting and Financial Reporting for Uncertainty in Income Taxes, Docket AI07-2-000,

119 FERC ¶ 62,167, p. 64454 (May 25, 2007) (emphasis added). Romines further testified that

                                                 39
the Commission “is not in a position to determine how accurate a utility’s FIN 48 adjustment is

for ratemaking purposes” and, as was the case with Oncor, is simply incapable of making such

determination because many documents on which the utility bases its adjustment are privileged.

                Staff witness Ellen Blumenthal testified that FIN 48 is “intended to make public

financial statements more comparable and relies on management’s assessment of the reasonableness

of tax positions taken” and that if Oncor “did not believe it had reasonable support for a tax position,

presumably it would not adopt that position in a filed tax return.” Because, she continued, ratemaking

is based on known and measurable amounts—not estimates or management’s opinion—no

adjustments to the filed tax return should be recognized, as Oncor urged FIN 48 required.

Blumenthal testified that the Commission’s pre-FIN 48 treatment of uncertain tax positions allows

for the very adjustments that Oncor seeks by virtue of a utility’s ability to reflect IRS audit

adjustments in its books and records as a known and measurable change, which is a recognized

ratemaking practice.

                Oncor’s own witness, Misty Burns, testified that the “whole purpose underlying

FIN 48,” which was required by the Sarbanes-Oxley Act, was to make “the entity’s financial

statements more accurately reflect its actual financial condition.” Burns also testified that, even

before FIN 48, all uncertain tax positions were “running on the IRS’ ‘interest clock.’” However, as

noted by Commission witnesses, the fact that an uncertain tax position might be rejected by the IRS

and later result in the payment of overdue taxes and interest does not change the fact that the utility

has, in the meantime, had access to the cost-free capital in the form of ratepayers’ payments.

                We conclude that the record contains substantial evidence from which the Commission

could reasonably have determined that Oncor may not deduct its FIN 48 uncertain tax positions

                                                  40
from its ADFIT account balance. The Commission acted within its discretion to reject the testimony

of Oncor’s witnesses suggesting that FIN 48 requires a change to the Commission’s long-standing

treatment of tax deductions with respect to ADFIT account balances. Its decision was reasonable

in light of the record, its rule requiring utilities to use FERC accounting methods, and the FERC’s

guidance letters on this issue. See El Paso, 883 S.W.2d at 185 (under substantial-evidence rule,

court must uphold Commission’s determination if there is reasonable basis for it). Accordingly, we

overrule Oncor’s second issue.


3.     ADFIT assets for pensions

               PURA section 36.065 provides that reasonable utility expenses for pensions and

other post-employment benefits (OPEBs), “as determined by actuarial or other similar studies in

accordance with generally accepted accounting principles,” are to be included in a utility’s rates.

PURA § 36.065. In its fourth issue, Steering Committee challenges the Commission’s Finding

of Fact 61 and Conclusion of Law 13 concluding that Oncor’s requested ADFIT assets for its

pension plan and OPEBs16 were properly included in its rate base. Steering Committee argues that

ratemaking and accounting principles require that if there is an ADFIT asset, there must be a

“counter-balancing” liability on the utility’s books that reflects the “timing difference” inherent to

ADFIT and that the record does not contain substantial evidence demonstrating that Oncor included


       16
           The issue on appeal and decided by the Commission involved Oncor’s ADFIT assets for
one other employee-related expense besides pensions and OPEBs: so-called “financial accounting
standards (FAS) 112 liabilities.” Because the details of the three types of expenses are not relevant
to this dispute and because the parties and Commission have treated them collectively, we use the
term “pensions” in this section for simplicity’s sake but note that it incorporates by reference OPEBs
and FAS 112 liabilities.

                                                 41
such liabilities in its rate-base calculation. Oncor responds that substantial evidence supports the

Commission’s decision and that the Commission acted within its discretion in crediting the

testimony of its experts over that of Steering Committee’s sole witness on the issue.

               Steering Committee’s argument is based on the following testimony of its witness

Lane Kollen, explaining why he believed Oncor’s proposal to include its asset ADFIT amounts for

pensions in rate base was inappropriate:


       There are no corresponding reductions to rate base for pension, OPEB or FAS 112
       liabilities. It is not appropriate to increase rate base for the tax effect of liabilities
       that are not used to reduce rate base. The Company’s proposal creates a one-sided
       mismatch between rate base components that necessarily are interdependent. Either
       both should be included in rate base or both should be excluded from rate base.


Beyond this evidence, Steering Committee has not identified a statute, regulation, or evidence

supporting its argument on appeal that Oncor’s computation of its ADFIT assets for pensions

was flawed because of a failure to “counter-balance” pension assets with liabilities reflecting the

“timing differences” Steering Committee asserts in its appellate briefs.

               In direct rebuttal of Kollen’s testimony, Oncor’s expert witness Misty Burns testified

that Oncor’s cash-working-capital study did in fact incorporate the corresponding liabilities related

to pensions and that even Kollen conceded that fact, by virtue of his recommending a different

computation of lead days for the pension component of that study:


       The ADFIT asset balances for pension, OPEB and FAS 112 liabilities represent
       a timing difference in the recognition of expense for these liabilities and cash
       payments that have been made. The cash working capital study has taken into
       consideration the leads and lags in expenses and payments, which results in
       corresponding adjustments to rate base. The accrued expenses related to

                                                  42
       pension, OPEB and FAS 112 liabilities are included in the Company’s cash
       working capital study and are properly reflected in rate base. It is rather
       remarkable that Mr. Kollen can make his argument considering that he has even
       provided testimony . . . proposing a different lead day figure for pension expense as
       part of the cash working capital allowance. Therefore, as Mr. Kollen’s own testimony
       highlights, Oncor has not created a one-sided mismatch between interdependent rate
       base components. The Company has appropriately included the ADFIT assets as
       well as the underlying liability in rate base. It is appropriate for these ADFIT assets
       to be included in rate base, and the Commission has accepted their inclusion in prior
       rate filings, most recently in AEP Central Docket No. 33309. (Emphasis added.)


               Oncor expert witness W. Alan Ledbetter, who prepared the cash-working-capital

study, expanded on Burns’s testimony by specifically explaining that the “third-party operation

and maintenance category” in the cash-working-capital study included employee benefits such as

pensions. In detailed rebuttal testimony, Ledbetter explained that Kollen’s recommendation that

Oncor’s pension expense be removed from the “third-party operations and maintenance expense”

category and placed into its own category in the cash-working-capital study would have resulted in

substantially the same result as Ledbetter’s calculation. Ledbetter went into great detail about why,

in his opinion, Kollen’s proposal to reduce ADFIT amounts for pensions was faulty. Ledbetter’s

explanation also referenced new legislation—the Pension Protection Act of 2006—supporting

Oncor’s treatment of its ADFIT assets for pensions, which Kollen did not address in his testimony.

               Additionally, Kollen’s own recommendation that Oncor should remove the pension

expenses from the “operations and maintenance” category and place them into their own is an

acknowledgment that Oncor did, indeed, include those expense ADFIT amounts, contrary to the

claim Steering Committee now makes on appeal. Although Kollen expressed his professional

opinion about why the cash-working-capital study did not appropriately reflect the liability ADFIT



                                                 43
amounts for pensions, the ALJs and the Commission were free to weigh his opinion against those

of Ledbetter and Burns supporting Oncor’s requested ADFIT assets for pensions, and we “must

resolve all evidentiary conflicts in favor of the Commission’s decision.” See Office of Pub. Util.

Counsel, 303 S.W.3d at 915; see also Citizens Against Landfill Location v. Texas Comm’n on Envtl.

Quality, 169 S.W.3d 258, 267 (Tex. App.—Austin 2005, pet. denied) (“the Commission, as the final

judge of the validity and credibility of expert testimony, may accept or reject part or all of a witness’s

conclusions”). Because there is substantial evidence supporting the Commission’s decision to include

Oncor’s ADFIT pension assets in its rate base, we overrule Steering Committee’s fourth issue.


D.      Oncor’s restructuring costs

                Oncor’s fourth issue alleges that the Commission erred in not allowing it to create

a “regulatory asset” so that it may recover its 2004 and 2006 business restructuring costs. Oncor

claims that the Commission departed from its precedent without sufficient explanation and that the

Commission’s factual findings are erroneous because they impose several new requirements on

Oncor. The Commission, Steering Committee, and Alliance respond that Oncor was not entitled to

recover its restructuring costs because it had already realized associated savings in excess of those

costs, Oncor is not authorized by statute or rule to create a regulatory asset under the facts in this

case, the precedent that Oncor cites is factually distinguishable, and substantial evidence supports

the Commission’s reasonable findings and decision.

                “Regulatory assets are essentially bookkeeping entries that reflect a charge to be

included in a utility’s future rates.” Corpus Christi, 51 S.W.3d at 238. Regulatory assets provide



                                                   44
an exception to the general principle that “regulatory lag” (the delay between the time when a

utility’s profits are above or below standard and the time when an offsetting rate decrease or increase

may be put into effect by Commission order or otherwise) is ordinarily an element of risk associated

with investment in a utility. State v. Public Util. Comm’n, 883 S.W.2d 190, 193 n.3, 196 (Tex. 1994).

                The Commission may, in its discretion, alleviate the impact of regulatory lag in order

to fulfill its statutorily imposed duties, but it may not do so unless necessary to comply with the

provisions of PURA. Id. at 196; see PURA § 36.051 (Commission must set revenues at level that

will permit utility reasonable opportunity to earn reasonable rate of return on invested capital

used and useful in providing service to public over and above reasonable and necessary operating

expenses). Therefore, courts have approved the use of regulatory assets for investments made during

a regulatory lag period only when such so-called “deferred accounting” was necessary to protect

the financial integrity of the utility. See State v. Public Util. Comm’n, 883 S.W.2d at 196-97

(requirement in PURA section 36.051 that utility recover expenses plus reasonable return on

investments is only met if return is sufficient to assure confidence in financial integrity of enterprise).

Thus, under certain circumstances, the Commission has the authority to grant deferred-accounting

treatment by allowing a utility to carry on its books so-called “regulatory assets.” See id.; see also

Office of Pub. Util. Counsel v. Public Util. Comm’n, 888 S.W.2d 804, 808 (Tex. 1994) (rejecting

“measurable harm” standard to determine whether utility may record regulatory asset and requiring

higher burden of “financial integrity” standard).

                The Commission normally follows a two-step process for allowing regulatory

assets: first, it gives the utility permission to implement the accounting mechanism to record



                                                    45
and defer the expense, and then, it allows later recovery of the expense, subject to the same review

as any other asset at the next rate hearing. See West Tex. Utils. v. Office of Pub. Util. Counsel,

896 S.W.2d 261, 265 (Tex. App.—Austin 1995, no writ). Thus, the creation of regulatory assets

is a function of the Commission’s discretion but is limited by its statutory authority. Oncor has cited

no statute or regulation requiring the Commission to allow utilities to recover for regulatory assets,

and we therefore consider whether the Commission abused its discretion in not allowing Oncor to

recover its restructuring costs.

                Oncor sought to include in its regulatory assets the costs it incurred in two separate

restructuring efforts. The first, in 2004, was a program Oncor initiated to significantly reduce

administrative and general support expenses by outsourcing various business functions and reducing

its workforce. Oncor witness R. Keith Pruett testified that the 2004 restructuring cost Oncor

$11,318,435 but resulted in annual savings of $3,403,781. The second effort in 2006 involved yet

more workforce reductions (accompanied by severance pay) and cost the company $8,956,405,

with an expected annual savings of $9,782,000. Because neither of these restructuring efforts

occurred during the test year, Oncor could not include them in its “cost of service” as a matter of

course. See 16 Tex. Admin. Code § 25.231 (rates are to be based upon electric utility’s cost of

rendering service to public during historical test year, adjusted for known and measurable changes).

Thus, Oncor deferred these costs on its accounting books and sought to recover them in its rate base

as regulatory assets.17




        17
         It is undisputed that Oncor unilaterally deferred these restructuring costs and did not first
obtain Commission approval to do so.

                                                  46
                The uncontroverted evidence showed that, by the time of the hearings in this

proceeding, Oncor had already realized savings in excess of its restructuring costs. Several witnesses,

including those representing the Commission, Steering Committee, and the Alliance, testified

that—while Oncor’s restructuring efforts reduced its operating and maintenance expenses (which

necessarily benefits ratepayers)—instead of using the savings therefrom to defray the costs associated

with restructuring, Oncor passed those savings on to its shareholders in the form of increased income

for the relevant years.18

                Nonetheless, Oncor alleges that in denying it recovery of the restructuring costs, the

Commission departed from its prior precedent and “policy” regarding regulatory assets by imposing

“new requirements” that the Commission had not previously required of other utilities. We disagree.

First, the facts and circumstances in the prior dockets that Oncor cites are distinguishable from this

case, making them inapplicable as precedent. For instance, the utility in Docket 11735—Oncor’s

predecessor Texas Utilities (TXU) Electric Company—was allowed to recover restructuring costs

as a regulatory asset, but those costs were projected rather than already incurred. Therefore, the

projected savings could be provided to customers by including them in rates before the savings

actually occurred, rather than those savings having already benefitted the shareholders (rather than

the ratepayers) as occurred here. See Tex. Pub. Util. Comm’n, Application of Tex. Utils. Elec. Co.

for Auth. to Change Rates, Docket No. 11735, 1993 WL 856544 (Nov. 15, 1993) (PFD), and


        18
           Oncor’s witness Pruett characterized the company’s provision of the savings to
shareholders rather than ratepayers thus: “The savings did nothing more than help reduce Oncor’s
under-earnings during the [relevant] period.” The ALJs rejected his opinion that, unless the company
over-earned its authorized rate of return, it was entitled to recover the costs from ratepayers and
instead agreed with the arguments presented by Commission staff, Steering Committee, and Alliance
that Oncor should have passed these savings on to ratepayers.

                                                  47
1994 WL 833163 (May 27, 1994) (second order on rehearing). Steering Committee witness Jacob

Pous opined that this difference in timing between prospective savings that are accounted for in

current rates and retroactive savings that have already been realized is significant because it affects

the equitable balance between shareholders and ratepayers. He further opined that allowing Oncor

to recover its restructuring expenses under the facts here would result in a double recovery.

                Dockets 21527 and 22350, also cited by Oncor, were part of the restructuring of

Oncor’s predecessor, TXU Electric Company, into its constituent parts as a step towards the

introduction of competition in the electric industry. See Tex. Pub. Util. Comm’n, Re TXU Elec. Co.,

Docket No. 22350, 2001 WL 1861521 (Oct. 3, 2001) (order); Tex. Pub. Util. Comm’n, Application

of TXU Elec. Co. for Fin. Order to Securitize Regulatory Assets & Other Qualified Costs, Docket

No. 21527, 2000 WL 33959149 (Apr. 19, 2000) (draft financing order). As such, those cases were

governed by specific statutes, one which defined “regulatory assets” for the purposes of the

deregulation period (specifically, the year 1998) and one which explicitly allowed recovery for costs

of workers displaced by the transition to competition. See PURA §§ 39.302(5), .906. Important to

the considerations in those dockets was the legislature’s determination that equity required utilities

to recover certain regulatory assets as part of a comprehensive restructuring of the electric industry.

See id. §§ 39.301, .906. However, there are no similar legislative commands at issue in this case,

and Oncor’s restructuring costs at issue here were not incurred until well after the deregulation

of the industry.19




        19
         Additionally, unlike Oncor’s proposal here and according to Oncor’s own witness, in
Docket 22350 TXU actually offset the restructuring savings against their associated costs.

                                                  48
               Secondly, we cannot discern from these three prior decisions any established

“policy” of the Commission requiring the approval of a regulatory asset merely because the utility

so requests.20 Rather, the only discernible policy these dockets reflect is that the Commission may,

in its discretion, allow regulatory assets when equitable to do so or otherwise required by law.

Consequently, we do not regard the Commission’s prior decisions as establishing any particular set

of requirements that a utility must meet to have a regulatory asset approved. Rather, the Commission

may approve regulatory assets on a case-by-case basis. In adopting the ALJs’ proposal on this issue,

the Commission reasonably determined that Oncor’s request to recover its restructuring costs should

be denied on the basis of three reasonable findings and conclusions: (1) Oncor did not use its savings

to defray costs associated with the restructuring; (2) the restructuring costs were not essential to

Oncor’s financial integrity; and (3) Oncor’s regulatory assets were not preapproved by the

Commission or authorized by statute. We must therefore affirm those findings and the Commission’s

ultimate decision if supported by substantial evidence. See El Paso, 883 S.W.2d at 185.

               Our review of the administrative record reveals that there is substantial evidence to

support the Commission’s decision. Witnesses for the Commission, Alliance, and Steering Committee

testified that by the time of the ratemaking hearings, Oncor had already realized cost savings in

an amount exceeding the restructuring costs and that, moreover, the savings had inured to the

company’s shareholders rather than its ratepayers.21 Steering Committee witness Pous testified that

       20
          Indeed, Oncor’s own witness Pruett conceded on recross-examination that the Commission’s
three prior decisions did not automatically entitle a utility in a future case to approval of its
regulatory assets.
       21
         There was some dispute as to the amount by which Oncor’s savings had exceeded its
costs—for instance, Commission staff witness Mary Jacobs testified that Oncor had already realized

                                                 49
allowing Oncor to characterize its restructuring costs as regulatory assets and recover those expenses

through this proceeding would result in a double recovery. Similarly, Commission staff witness

Jacobs testified that it is not in the public interest to defer the restructuring costs when Oncor would

fully recover them through cost savings prior to the effective date of the rate change. Oncor did not

dispute that it failed to obtain preapproval of these regulatory assets or that no statute or regulation

required the Commission to allow Oncor’s recovery for them. And, Oncor’s own witness Pruett

testified that recovery of the restructuring costs was not necessary to assure Oncor’s financial

integrity.   This amounts to substantial evidence to support the Commission’s reasonable

determination that it was not equitable to allow Oncor to recover its 2004 and 2006 restructuring

costs through the mechanism of regulatory assets. Accordingly, we overrule Oncor’s fourth issue.


III.    Expense issues


A.      Federal income-tax expense


The dispute and background

                Several parties appeal the Commission’s dual determinations that (1) because Oncor

is taxed as a partnership, it is not a “member of an affiliated group eligible to file a consolidated

federal income tax return” under PURA section 36.060 and therefore did not have to include in its

federal income-tax expense a so-called “consolidated tax savings adjustment” (CTSA) to pass along



$240.6 million in savings without offsetting any of the $20.3 million that it sought to capitalize as a
regulatory asset. Although Oncor takes issue with Jacobs’ estimate as too high due to “misconstruing”
Oncor’s underlying data, the testimony of Oncor’s own witnesses supports the finding that Oncor’s
savings had already exceeded its costs.

                                                  50
to ratepayers the resulting tax savings, see Act of May 8, 1997, 75th Leg., R.S., ch. 166, § 1, 1997

Tex. Gen. Laws 713, 774 (amended 2013) (current version at PURA § 36.060);22 and (2) Oncor’s

federal income-tax expense should be calculated as if it were a conventional corporation, even

though it is taxed as a partnership. In accordance with these legal conclusions, the Commission

allowed Oncor to include the entirety of its requested $151 million federal income-tax expense in

its cost of service. Appellants contend that the Commission erred in its application of PURA section

36.060 and that the Commission was required to apply a CTSA to Oncor’s income-tax expense.23

They additionally assert that the Commission’s conclusions on this issue were arbitrary and

capricious by considering an irrelevant factor (a tax-sharing agreement between Oncor and its parent

and affiliates) and by acknowledging Oncor’s partnership tax status for the limited purpose of

precluding application of section 36.060 while simultaneously ignoring that status in determining

that Oncor’s tax expense should be calculated as if it were a conventional corporation.24


       22
            PURA section 36.060 was amended in 2013 and now reads significantly differently than
it did at the times relevant to this dispute. Compare Act of May 20, 2013, 83d Leg., R.S., ch. 787,
2013 Tex. Gen. Laws 2003 (eff. Sept. 1, 2013) (current version at PURA § 36.060), with Act of May
8, 1997, 75th Leg., R.S., ch. 166, § 1, 1997 Tex. Gen. Laws 713, 774 (amended 2013) (current
version at PURA § 36.060). This dispute concerns the version of section 36.060 in effect prior to
2013, and our references to “section 36.060” and “PURA § 36.060” are to that former version.
       23
           The OPUC additionally complains that the Commission failed to apply a CTSA to Oncor’s
state franchise-tax expense because it was eligible to file a consolidated return with respect to that
tax. See Tex. Tax Code § 171.1014 (requiring “affiliated group engaged in a unitary business” to
file “combined group report” with respect to state franchise tax). However, the OPUC has failed to
adequately brief this issue and has, therefore, waived appellate review. See Tex. R. App. P. 38.1(i).
       24
          Within this same issue, the Alliance and Steering Committee complain that because Oncor
is taxed as a partnership and pays no taxes itself, no income-tax expense at all should have been
included in its cost of service. The supreme court has rejected this argument. See Suburban Util.
Corp. v. Public Util. Comm’n, 652 S.W.2d 358, 364 (Tex. 1983) (even though subchapter-S
corporation pays no taxes itself, taxes its shareholders pay are “inescapable business outlays” that
are recoverable in rates).

                                                 51
               The relevant factual background includes the fact that for many years before and

throughout most of the 2007 test year Oncor had been a conventional corporation (under its former

name, TXU Electric Delivery Company) wholly owned by its parent company, EFH.25 Accordingly,

in previous ratemaking proceedings the Commission had applied a CTSA to Oncor’s income-tax

expense. Through at least 2007, EFH filed consolidated federal income-tax returns on behalf of

itself and its various affiliates, including Oncor. In October 2007, Oncor became a Delaware limited

liability company (LLC) but remained wholly owned by EFH (through a chain of holding companies

also wholly owned by EFH), and its income was legally eligible to be included in the affiliated

group’s consolidated return for the year because of its tax status as a “disregarded entity,” meaning

that for tax purposes it was essentially a division within EFH. See 26 C.F.R. § 301.7701-2(a), (c)(2)

(2014) (Internal Revenue, Business Entities; definitions) (business entity with only one owner

is either classified as corporation or “is disregarded as an entity separate from its owner”; if

disregarded, entity is treated in same manner as if it were division of owner).

               Contemporaneous with Oncor’s becoming an LLC, it executed a tax-sharing

agreement with EFH and its affiliates because, as stated in the agreement’s opening recitals, the

parties “wish[ed] to file” consolidated returns. The agreement provided that—regardless of its tax

classification under the tax laws—Oncor would compute its income-tax liability as if it were a




       25
          EFH (Energy Future Holdings Corporation) had previously been called TXU Corporation;
for simplicity’s sake, we refer to the parent company by its current name, EFH, regardless of its
actual name at the relevant time.

                                                 52
stand-alone, conventional corporation and pay such amount to the IRS, and accordingly Oncor

would not be permitted to file a consolidated return with the EFH affiliated group.26

                On November 5, 2008—while the ratemaking proceedings at issue were underway

and almost two years after the start of the test year—EFH sold to two investors a total of 19.96%

interest in Oncor, retaining a majority 80.04% interest (again, through a chain of wholly owned

subsidiary holding companies). Upon the minority-interest sale, Oncor ceased being considered a

“disregarded entity” for federal tax purposes and became taxable as a partnership because it did not

file an election to be taxed as a corporation. See id. § 301.7701-3(a), (b)(I) (entity with at least two

members that is not “incorporated” under state law can elect to be classified as corporation or

partnership; if it does not file election, default tax classification is partnership).

                Because the record does not contain tax-filing evidence pertaining to the affiliated

group for the year 2008, it is not clear whether EFH filed a consolidated return for that year or in

subsequent years. However, Oncor has cited no evidence indicating EFH’s intent to cease filing

consolidated returns or any evidence indicating other changes in its affiliates’ business structuring




        26
            Appellees claim this tax-sharing agreement served to “ring-fence” Oncor from its affiliates’
liabilities. In its Order, the Commission specifically and repeatedly disavowed the agreement or
Oncor’s “ring-fenced” status as being factors in its determination of the tax-expense issue: “The
Commission emphasizes that it is not basing its [tax expense] decision on the tax-sharing agreement
between Oncor and [EFH],” and “The Commission is not determining Oncor’s federal income tax
expense on the basis of its tax-sharing agreement with EFH.” Furthermore, the Commission stated
that the tax-sharing agreement is “not binding on the Commission” because the “Commission has
neither addressed nor approved” it. Yet, remarkably, the Commission simultaneously found that
“Oncor is a ring-fenced utility that has entered into a tax-sharing agreement with EFH and its
affiliates that requires Oncor to function as a stand-alone company” and that “[i]t is appropriate to
determine Oncor’s federal income tax expense included in its revenue requirement as if it were a
stand-alone, conventional corporation.”

                                                   53
that would affect their privilege to file a consolidated return. See 26 U.S.C. §§ 1501, 1504 (affiliated

group of corporations has privilege of filing consolidated return, and main attribute of eligibility is

that each company in group is at least 80% owned by parent or another company in group). And,

had EFH filed a consolidated return post-2007 and had the tax-sharing agreement not been in effect,

at least 80.04% of Oncor’s income would have been included in the consolidated return by virtue

of EFH’s ownership interest in Oncor and the flow-through tax treatment of Oncor’s income.

                Oncor and the Commission argue that by virtue of the sale of the minority interests

(and Oncor’s corresponding election to be taxed as a partnership rather than a corporation), Oncor

became “ineligible” to file a consolidated tax return with EFH and its other affiliates. Appellants

counter that Oncor is eligible because its tax status is entirely within its own (or EFH’s) control and,

therefore, qualifies the utility for the privilege of filing a consolidated return.


Former PURA section 36.060

                The Commission’s regulations permit a utility to include in its cost of service its

“allowable expenses” and provide that “in computing an electric utility’s allowable expenses

[including federal income taxes], only the electric utility’s historical test year expenses as adjusted

for known and measurable changes will be considered.” 16 Tex. Admin. Code § 25.231(b) (emphasis

added). Its regulations also explicitly prescribe the calculation of income-tax expenses: “federal

income taxes shall be computed according to the provisions of the Public Utility Regulatory Act

§ 36.060.” Id. § 25.231(b)(1)(D). The main issue on appeal concerns how the Commission interpreted

section 36.060, which at the relevant time provided:




                                                   54
        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 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 tax return; and

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


Act of May 8, 1997, 75th Leg., R.S., ch. 166, § 1, 1997 Tex. Gen. Laws 713, 774 (amended 2013)

(current version at PURA § 36.060) (emphases added).

                 The Commission concluded that Oncor is not currently a “member of a group eligible

to file a consolidated tax return” because it is “taxed as a partnership,” and therefore section 36.060’s

requirement that Oncor’s federal income-tax expense be reduced by its “fair share” of the savings

resulting from such consolidation (the so-called CTSA) did not apply.27 Thus, the Commission made

no downward adjustment to Oncor’s requested federal income-tax expense, permitting it to include

the entirety of its requested $151 million in its reasonable and necessary expenses, which amount

was based on Oncor’s taxes calculated as if it were a corporation even though it is taxed as a

partnership. Appellants assert that the Commission erred in making this determination and that a

CTSA was required because Oncor was and remains a member of a group eligible to file a

consolidated tax return and that it in fact filed a consolidated return with its parent and affiliates in

the test year.


        27
           The Commission’s Finding of Fact Number 128A stated, “Oncor is not currently a
member of an affiliated group eligible to file a consolidated federal income tax return,” and its
Conclusion of Law Number 19A stated, “PURA § 36.060 does not apply to Oncor as it is not
currently a member of an affiliated group eligible to file a consolidated tax return.”

                                                   55
                We initially note the mandatory language of former section 36.060: a utility’s

income taxes “shall be computed as though a consolidated return had been filed and the utility had

realized its fair share of the savings resulting from that return” if certain conditions are met.28 PURA

§ 36.060 (emphasis added). This mandatory language requires the Commission to compute a CTSA

in order to pass along to ratepayers not only actually realized tax savings achieved via a consolidated

return but even unrealized or hypothetical tax savings that have been forgone by a utility and

its affiliates in unreasonably choosing not to consolidate returns when they are able to do so.

The legislative intention expressed in section 36.060 requires that available tax savings inure to

ratepayers. See Reliant Energy, 153 S.W.3d at 199 (CTSA is performed for ratepayers’ benefit);

see also Public Util. Comm’n v. Houston Lighting & Power Co., 748 S.W.2d 439, 442 (Tex. 1987)

(holding that tax savings generated by utility’s expense write-off should inure to ratepayers). In

other words, section 36.060 requires that if there is a tax benefit to be gained via consolidation of

returns, the utility and its affiliates must either take the necessary steps to actually consolidate returns

so as to pass along the potential tax savings to ratepayers or—by unreasonably choosing not to

consolidate—absorb the “loss” of a CTSA that the utility may not recover in rates. Either way, the

public (ratepayers) will receive the benefit provided by the applicable federal tax laws. See 26

U.S.C. § 1501 (affiliated group of corporations has privilege of filing consolidated return in lieu of

separate returns).




        28
            We refer to these conditions as the “reasonableness” and “advantageous” prongs herein:
when a utility is eligible to file a consolidated return but has not, a CTSA must be applied unless (1)
the utility’s decision not to consolidate was reasonable and (2) consolidation would not have been
advantageous to the utility. See PURA § 36.060.

                                                    56
                Furthermore, the plain language and grammatical construction of section 36.060

implies that if the utility has in fact been a participant in a consolidated return in a test year, then the

hypothetical inquiries into what would have been the tax savings and into the “reasonableness” and

“advantageous” prongs of section 36.060 is moot—the Commission must determine the amount of

the consolidated group’s actually realized tax savings and allocate to the utility its fair share thereof.

See PURA § 36.060 (“unless it is shown . . . that it was reasonable to choose not to consolidate

returns . . . .”). In other words, the “reasonableness” and “advantageous” prongs of section 36.060

are operative only when determining a utility’s hypothetical tax savings if a consolidated return has

not been filed; they do not have any effect when a consolidated return has in fact been filed.

                “Ratemaking begins with an historic test year.” Public Util. Comm’n v. GTE-Sw.,

Inc., 901 S.W.2d 401, 411 (Tex. 1995); see 16 Tex. Admin. Code § 25.231(b). In the present case,

the Commission was presented with the uncontroverted fact that in the test year Oncor did file a

consolidated return with EFH and its affiliates, and there were significant tax savings as a result

thereof. In fact, the tax savings were so significant that after offsetting the income of its profitable

subsidiaries (including Oncor) with that of its unprofitable ones, EFH had a net loss and paid zero

federal income taxes. Yet, rather than calculate Oncor’s income-tax expense by allocating to Oncor

its fair share of the tax savings actually realized by the group on its 2007 return, the Commission

determined that section 36.060’s mandate no longer applied to Oncor’s tax calculation because

Oncor’s tax status had changed—nearly two years after the end of the test year—and it was therefore

no longer “eligible” to file a consolidated return.




                                                    57
               Because the Commission did not explain why it looked to Oncor’s tax status at the

time of the ratemaking proceedings rather than during the test year in determining whether section

36.060 applies, we can only surmise that it considered Oncor’s tax-status change a “known and

measurable change.” See 16 Tex. Admin. Code § 25.231(b); see also GTE-Sw., 901 S.W.2d at 411

(historic test year amounts must be adjusted to more accurately reflect known costs to be incurred

in future). However, while the Commission may adjust test-year expenses for “known and measurable

changes,” it is axiomatic that such change must be relevant to the expense at issue by having a

measurable and real effect on it. The only changes cited by appellees as potentially constituting

“known and measurable changes” are: (1) the sale of the minority interests, resulting in Oncor’s

taxation status changing to that of a partnership, and (2) the execution of the tax-sharing agreement,

requiring Oncor to calculate and pay its taxes as a stand-alone corporation (without making such tax

election). We hold that neither of these changes is relevant to section 36.060’s applicability and

requirement that the Commission apply a CTSA.

               First, despite the minority sale, EFH and its subsidiaries (including Oncor) continue

to meet the 80% ownership/control test, qualifying the group to consolidate returns. Second, the

only reasonable interpretation of “member” in section 36.060 necessarily still includes Oncor, and

we hold that the meaning of the phrase “member of an affiliated group eligible to file a consolidated

tax return” is not ambiguous. Appellees contend that only bona fide “corporations” (or those taxed

as such) may be “members” of an “affiliated group eligible to file a consolidated return.” See 26

U.S.C. §§ 1501 (“affiliated group of corporations shall . . . have the privilege of making a

consolidated return” (emphasis added)), 1504 (defining affiliated group of corporations as chain of

corporations connected through stock ownership with common parent where parent owns at least

                                                 58
80% of at least one other corporation in group and where each other corporation is at least 80%

owned by one or more of others). Because Oncor has not made an election to be taxed as a

corporation, their argument goes, it is taxed as a partnership and is therefore not a “corporation” with

respect to section 36.060 and applicable income-tax laws. However, the analysis does not end there.

                For federal tax purposes, the term “corporation” includes “an association,” see

26 C.F.R. § 301.7701-2(b)(2), which is defined as “an entity with at least two members” that “can

elect to be classified as either an association (and thus a corporation under § 301.7701-2(b)(2)) or

a partnership,” see id. § 301.7701-3(a) (2014) (Internal Revenue, Classification of certain business

entities). Oncor is an “association” and therefore may choose to be taxed either as a partnership (by

default) or as a corporation (by merely filing a form). See id. § 301.7701-3(b), (c). Thus, the Internal

Revenue Code’s determination of whether a company is a member of an affiliated group of

corporations eligible to file a consolidated return turns not on the company’s legalistic label or

formal structure (e.g., “incorporated” vs. LLC) but merely on the existence of its legal right to be

taxed as a corporation.29 Accordingly, Oncor is a “member of an affiliated group eligible to file a

consolidated return” under section 36.060 because it is an entity with at least two members and is

more than 80% owned by EFH. Furthermore, appellees have identified no hindrance to Oncor’s

filing the necessary form to be taxed as a corporation.30

       29
           Appellees do not dispute that EFH and its subsidiaries besides Oncor compose an
“affiliated group” (meeting the 80% ownership/control test) for the purposes of filing consolidated
tax returns, nor do they dispute the facts that Oncor is 80% owned and controlled by EFH and that
EFH has in fact filed consolidated returns on behalf of the “affiliated group” for many years. It is
only the issue of whether Oncor is to be considered a “member” of that “affiliated group” because
of its taxation status that is before us on review.
       30
           Indeed, an election to be taxed as a corporation rather than a partnership would appear to
be in line with the very end Oncor apparently seeks: being a “ring-fenced,” stand-alone entity that

                                                  59
                Moreover, we conclude that the tax-sharing agreement is not a “known and

measurable change” affecting Oncor’s eligibility to file a consolidated return. In the purported

effort to “ring-fence” Oncor, EFH and its affiliates essentially agreed that Oncor is not eligible to file

a consolidated return, requiring it to pay its own taxes computed on a stand-alone, corporate basis.

However, section 36.060 provides no exceptions to its mandatory application for private, inter-

company agreements purporting to preclude an entity from being eligible to file such returns. It is

axiomatic that federal tax laws—not private agreements—provide the eligibility requirements for

federal tax benefits. See Black’s Law Dictionary 597 (9th ed. 2009) (“eligible” defined as “legally

qualified for an office, privilege, or status”). Although the tax-sharing agreement and Oncor’s

attendant decision not to consolidate may have resulted in Oncor’s paying more taxes than it did in

the test year (when it in fact consolidated returns), this type of increase in taxes would not affect the

analysis of whether section 36.060 applies but only the “reasonableness” and “advantageousness”

prongs, which are not before us on review.31

                Because Oncor has the legal right to choose to be taxed as a corporation, it is eligible

to file a consolidated return, and we hold that the Commission erred in determining that Oncor is not

a “member of an affiliated group eligible to file a consolidated return.” See PURA § 36.060. To hold

otherwise would favor the private interest of utility companies and their affiliates over the public


is insulated from the debts of its parent’s subsidiaries.
        31
            The Commission made no findings regarding whether a future consolidated return would
be advantageous to Oncor or whether Oncor would be reasonable in choosing not to participate in
such return. Its section 36.060 conclusion rested solely on its determination of Oncor’s “eligibility.”
Therefore, our review does not involve determining whether substantial evidence would support
either finding; we are left with reviewing only the findings and conclusions relating to Oncor’s
eligibility to file a consolidated return.

                                                   60
interest of the ratepayers and subvert the legislature’s intent. Furthermore, we hold that it was

arbitrary and capricious for the Commission to incongruously conclude both that Oncor is not eligible

to file a consolidated return because it has not elected to be treated as a corporation for income-tax

purposes, but that Oncor may still claim expenses for taxes as though it has made that election.

               The Commission should have begun its determination of the income-tax-expense

issue with Oncor’s actual income-tax expense for the 2007 test year and then adjusted that amount

for Oncor’s fair share of the tax savings realized from the EFH group’s filing of a consolidated

return. The sale of the minority interests, Oncor’s choice to be taxed as a partnership, and the tax-

sharing agreement are not relevant factors to the expense calculation or “known and measurable”

changes affecting the CTSA requirement in section 36.060. That EFH and its affiliates have agreed

amongst themselves to allow EFH to retain the benefits of tax consolidation does not alter the

mandatory language of section 36.060, which requires those benefits to inure to the ratepayers.

               The Commission was statutorily required by section 36.060 to apply a CTSA to

Oncor’s federal income-tax expense. Accordingly, we reverse the Commission’s determinations

relating to Oncor’s federal income-tax expense and remand the issue to the Commission for

recalculation in accordance with section 36.060 and consistent with this opinion.


B.     Self-insurance reserve accrual

               In its third issue, Steering Committee asserts that the trial court erred in affirming

the Commission’s Order increasing Oncor’s annual self-insurance reserve accrual because the

methodology that the Commission used to determine the amount is not supported by substantial

evidence and arbitrarily and capriciously reverses Commission precedent. Oncor and the Commission

                                                 61
respond that substantial evidence supported the Commission’s decision, which fell within the range

of amounts recommended by various witnesses, and that neither Commission precedent nor

applicable law requires the use of any particular methodology for computing the reserve accrual.

               PURA section 36.064 allows a utility to be self-insured, provided that the utility

can show that (1) its plan is in the public interest and is a lower-cost alternative to purchasing

commercial insurance, and (2) the ratepayers receive the benefit of the savings. PURA § 36.064.

No statute or regulation prescribes the particular methodology that must be used in setting the

amount of reserve accrual. Oncor and its predecessors have had a Commission-approved self-

insurance plan for over 30 years. In this rate case, Oncor sought to increase its authorized annual

self-insurance reserve accrual for future losses from about $5.3 million to about $57 million, basing

its request on a methodology using actuarial analysis. Steering Committee proposed that the annual

accrual be set at about $18.7 million, supporting its figure with a different methodology, called

historical averaging. The main reason Oncor sought to increase its reserve accrual was because it

had incurred a deficit of $146 million and would soon be adding another $70 million of losses from

the year 2008. It hoped to amortize the collection of its insurance deficit over the next five years.

There was no dispute in the ratemaking proceedings that Oncor required an increase in its annual

self-insurance reserve accrual; the dispute was about the amount of the increase.

               Witnesses for various parties, including Oncor, the Commission, and Steering

Committee, provided widely disparate opinions about the ultimate amount of reserve accrual that

was appropriate.32 Steering Committee argues that the Commission erred in accepting the ALJs’


       32
        Some of these variances occurred even within the historical-averaging-methodology camp.
For example, there were differences regarding the number of previous years that were to be averaged

                                                 62
recommendation to set the annual reserve accrual at $33,284,430.45, which was arrived at by

averaging two figures supported by testimony: one computed by using a ten-year historical average

and the other by using an actuarial analysis at a 50% “confidence level.”33 By doing so, Steering

Committee maintains, the Commission arbitrarily crafted a “blended” methodology that amounted

to an “entirely new procedure” unsupported by substantial evidence. The ALJs explained their

reasoning for choosing an amount within the range of figures supported by the two methodologies

was due to its conclusion that, while actuarial analysis is more “sophisticated,” neither methodology

is necessarily “more or less reliable,” and due to the fact that it was “evident that Oncor requires a

significant increase in its annual self insurance reserve accrual” because of its large reserve deficit

that would soon increase significantly.

               Steering Committee concedes in its reply brief that both methodologies and figures

were supported by substantial evidence; it is only the Commission’s decision to average the figures

resulting from the two methodologies that Steering Committee claims was erroneous. Steering

Committee claims that the Commission thereby improperly “embarked on its own method that goes

beyond anything in the record.” See Central Power & Light Co. v. Public Util. Comm’n, 36 S.W.3d

547, 557-58 (Tex. App.—Austin 2000, pet. denied) (holding that where “[n]o witness testified in


(i.e., five or ten). Other points of contention between the experts concerned issues such as whether
to include consideration of the extreme storms of 2004 and 2005 and whether to adjust the accrual
amount for losses due to employee misconduct.
       33
           In the context of actuarial studies, a “confidence level” signifies the degree of certainty
that actual losses will not exceed the amount indicated. For instance, at a 50% confidence level,
one can be certain that 50% of the time, the losses will not exceed the indicated amount. Oncor
advocated for a 75% confidence level but advanced the 50% level as an option if the Commission
deemed the 75% level too high. One of Oncor’s witnesses averred that none of the other parties’
recommended accruals met even the 10% confidence level calculated by its actuarial expert.

                                                  63
support of a method of calculating consolidated tax savings by determining today’s value of past tax

savings,” Commission’s use of method was improper). However, in averaging the results produced

by two methodologies that were each supported by the record, the Commission did not “embark on

its own method” but rather used an “amalgam of methods proposed by different witnesses,” which

is acceptable. See id. We reject Steering Committee’s contention that the Commission’s selecting

an amount within the range of figures supported by substantial evidence—which happened to be an

average of two figures arrived at by two different, competing methodologies—amounted to an

entirely “new” methodology.

               In crafting its order, the Commission is not bound to accept the testimony of any

witness but may accept or reject in whole or in part the testimony of the various witnesses who

testify. Id. at 557. It was reasonable for the Commission to accept or reject some or all of the

various witnesses’ testimony about their computations and to conclude that an amount in the middle

of those computations was fair and equitable to both Oncor and the ratepayers. The supreme court

has expressly held that the Commission may, in its discretion, select an amount within the range of

figures provided by expert testimony of the parties. El Paso, 883 S.W.2d at 186 (because Commission

selected one amount within range of figures provided by expert testimony, especially in light of

complexity of issue, appellants had not overcome presumption that Commission’s decision was

supported by substantial evidence).

               The Commission’s determination on the accrual amount was indisputably within the

range of figures provided by the various experts. Moreover, we note that the amount of reserve

accrual set by the Commission was within the range of witnesses’ calculations who used only



                                                64
the historical-averaging methodology advanced by Steering Committee (for instance, Commission

staff witness Katie Rich testified that averaging the previous five years’ losses would result in an

accrual level of $36.6 million, an amount more than that ordered by the Commission). Thus, even

if the Commission erred in using a figure computed with the actuarial methodology, there was

nonetheless substantial evidence to support its ultimate determination. See Public Util. Comm’n v.

Southwestern Bell Tel. Co., 960 S.W.2d 116, 121 (Tex. App.—Austin 1997, no pet.) (appellate court

must sustain agency order on any legal basis shown in record).

               In support of its argument that the Commission’s decision on this issue violates

its own “precedent,” Steering Committee’s appellate briefs cite only minimal support: (1) the PFD

wherein the ALJs noted that the Commission “chose not to accept” actuarial analysis in two other

dockets (Numbers 33309 and 34800), and (2) testimony from one witness that the actuarial analysis

has not “been historically applied at the Commission,” which used historical averaging (using a ten-

year period) in another recent docket. These references cannot suffice to have created binding

Commission “precedent” requiring the use of historical averaging to the exclusion of actuarial or any

other methodology for computing reserve accruals, and Steering Committee cites no case law or

other authority otherwise in support of its argument. We reject this argument and hold that the

Commission properly chose an amount for Oncor’s self-insurance reserve accrual that was within

a range of figures supported by expert testimony. Accordingly, we overrule Steering Committee’s

third issue.




                                                 65
C.     Franchise fees

               A municipality is authorized to charge a transmission and distribution utility a

franchise fee for the use of a municipal alley, street, or public way to deliver electricity to retail

customers within the municipality’s boundaries. PURA § 33.008(b). PURA sets out a formula to

determine the amount of franchise fee that the municipality is entitled to collect from each utility.

Id. (fee “shall be equal to the charge per kilowatt hour determined for 1998 multiplied times the

number of kilowatt hours delivered within the municipality’s boundaries”). Alternatively, a utility

may enter into an agreement with a municipality to establish a franchise fee at a different rate than

that prescribed by subsection (b) under certain circumstances:


       Notwithstanding any other provision of this section, on the expiration of a
       franchise agreement existing on September 1, 1999, an electric utility, transmission
       and distribution utility, municipally owned utility, or electric cooperative and a
       municipality may mutually agree to a different level of compensation or to a different
       method for determining the amount the municipality may charge for the use of a
       municipal street, alley, or public way in connection with the delivery of electricity at
       retail within the municipality.


Id. § 33.008(f). Regardless of whether franchise fees are set by subsection (b) (computed with the

statutory formula) or subsection (f) (set by agreement), they are deemed to be reasonable and

necessary operating expenses of the utility. Id. § 33.008(c) (“franchise charges authorized by this

section shall be considered a reasonable and necessary operating expense of each electric utility,

transmission and distribution utility, municipally owned utility, or electric cooperative”); see also

id. § 36.051 (in setting utility’s rates, Commission shall establish overall revenues at amount that




                                                 66
will permit utility to earn reasonable return on capital in excess of utility’s reasonable and necessary

operating expenses).

                In its rate-change application, Oncor sought recovery of over $250 million in

municipal franchise fees, including $5.6 million for a 5% increase in the franchise-fee rate that

Oncor allegedly agreed to pay pursuant to an agreement with Steering Committee. In the ratemaking

proceedings, Commission staff argued that Oncor’s agreement to pay 5% more in franchise fees than

the statutory formula prescribed in PURA section 33.008(b) was not a “reasonable and necessary”

expense and thus not recoverable. Oncor countered that subsection (f) of that same statute

specifically allowed it to increase its franchise-fee payments by agreement and that, therefore, the

5% increase in fees was “reasonable and necessary” as a matter of law.

                The ALJs agreed with Oncor’s interpretation of PURA section 33.008(f), noting

in their PFD that subsection (f) provides municipalities “the authority to negotiate an increased

franchise fee with the utility, and [the utility] to recover those fees in rates.” Accordingly, the ALJs

recommended no change to Oncor’s requested municipal franchise-fee expense. However, in its

Order, the Commission disagreed with the ALJs’ interpretation and reversed their findings and

conclusions regarding municipal franchise fees, concluding that “Oncor is not entitled to recover the

5% increase in the franchise fee rate that it agreed to pay pursuant to an agreement with Cities”

because “PURA § 33.008(b) specifies how to calculate municipal franchise fees owed by a utility

to municipalities within its service territory. . . . Since Oncor agreed to pay its municipalities 5%

more than the 2005 effective rate calculated pursuant to PURA § 33.008(b), it is not an expense that

is reasonable and necessary to provide service to the public.” Accordingly, the Commission reduced



                                                  67
Oncor’s recovery of franchise-fee expenses by about $5.6 million. Notably, neither the ALJs nor the

Commission made any specific fact findings about the requirements imbedded in subsection (f): that

a franchise agreement between the municipality and the utility existing on September 1, 1999 had since

expired, and the parties entered into a new agreement upon such expiration. See PURA § 33.008(f).

               In this suit for judicial review of the Commission’s Order, the district court agreed

with Oncor’s position and reversed the Commission’s determination that Oncor could not recover

the 5% increase in franchise fees that it alleged it was entitled to under renegotiated agreements

with Steering Committee. On appeal, the Commission urges that its franchise-fee determination

must be upheld because Oncor did not meet its burden of proving that it had franchise-fee

agreements in effect on September 1, 1999 that had since expired. In response, Oncor contends that

the evidence conclusively established that its previous franchise-fee agreements had indeed expired.

               Oncor also takes issue with the fact that in the ratemaking proceedings the

Commission did not raise or challenge the factual issue of whether the franchise agreements had

expired and has only raised this alleged factual deficiency on appeal. However, we must affirm the

Commission’s Order on any legal basis supported by the record, even if the Commission provided

an erroneous legal basis for its decision. See McMullen v. Employees Ret. Sys., 935 S.W.2d 189, 191

(Tex. App.—Austin 1996, writ. denied) (citing Railroad Comm’n v. City of Austin, 524 S.W.2d 262,

279 (Tex. 1975)).

               The Commission argues that we must affirm its Order on the legal basis of “no

evidence” because there is less than a scintilla of evidence to support Oncor’s burden that it had

agreements with Steering Committee effective on September 1, 1999, and that such agreements



                                                 68
expired thereafter. “When the evidence offered to prove a vital fact is so weak as to do no more than

create a mere surmise or suspicion of its existence, the evidence is no more than a scintilla and, in

legal effect, is no evidence.” Kindred v. Con/Chem, Inc., 650 S.W.2d 61, 63 (Tex. 1983); see also

Texas Dep’t of Pub. Safety v. Story, 115 S.W.3d 588, 595 (Tex. App.—Waco 2003, no pet.)

(substantial evidence standard bears semblance to traditional no-evidence standard of review). If,

indeed, the evidence supporting Oncor’s subsection (f) burden amounts to no more than a scintilla,

we must affirm the Commission’s Order because, legally, there is no evidence to support any finding

in favor of Oncor on this issue. See Torch Operating, 912 S.W.2d at 792-93 (substantial evidence

requires more than scintilla). Our review of the administrative record reveals that there was less than

a scintilla of evidence to support Oncor’s claim under subsection (f).

               Oncor points to only one direct reference in the record to the expiration of franchise-

fee agreements between Steering Committee and Oncor: the cross-rebuttal testimony of Oncor witness

Karl Nalepa. Nalepa’s testimony encompasses the entirety of evidence supporting Oncor’s claim that

the requisite agreements had expired and reads: “The 5% increase in franchise fees is the result of

negotiations between Steering Committee and the Company on expiration of the previously existing

franchise fees. Since the franchise fees were appropriately established under this section of PURA,

they are a reasonable and necessary operating expense of the Company, and should be included in

rates.” Nalepa’s conclusory testimony does not indicate when the franchise agreements expired or

whether the expired agreements were in force on September 1, 1999, as explicitly required by

subsection (f). This amounts to less than a scintilla of evidence supporting Oncor’s burden to prove

that the relevant agreements existed on September 1, 1999, and expired thereafter, because it does



                                                  69
no more than create a mere suspicion that the agreements at issue met the requirements of subsection

(f). Accordingly, we sustain the Commission’s first issue and reverse the district court’s judgment

on the issue of Oncor’s entitlement to recovery of reasonable and necessary expenses in the form of

franchise fees allegedly agreed to in Oncor’s agreements with Steering Committee.


D.     Incentive-compensation payments

               Oncor’s fifth issue asserts that the Commission’s denial of approximately $5 million

of the $19.5 million it sought in recovery for payment of incentive compensation to its employees

was not supported by substantial evidence. The Alliance, the Commission, and TIEC respond that

substantial evidence supports the Commission’s decision, which comports with Commission

precedent disallowing compensation payments that are tied to financial-performance measures

rather than those tied to strictly operational measures such as reliability and safety.34 Because

the question of whether Oncor’s incentive-compensation payments were “financial” rather than

“operational” in nature is one of fact, we must uphold the Commission’s decision if it was

reasonable in light of the record and supported by substantial evidence, even if the evidence

preponderates against its decision. See Charter Med., 665 S.W.2d at 452.


       34
           The Commission has historically allowed the recovery of incentive compensation tied to
operational performance because it more immediately benefits the ratepayers but has denied the
recovery of incentive compensation tied to financial performance because it more immediately
benefits the shareholders. For instance, in Docket No. 33309, the Commission determined that “the
inclusion of annual and long-term incentive compensation related to financial incentives in cost
of service is unreasonable because it is not necessary for the provision of . . . utility services.”
Tex. Pub. Util. Comm’n, Application of AEP Tex. Cent. Co. for Auth. to Change Rates, Docket
No. 33309, 2008 WL 727056, (Mar. 4, 2008) (order on rehearing); see Tex. Pub. Util. Comm’n,
Re Entergy Gulf States, Inc., Docket No. 34800, 2008 WL 5451520 (Nov. 7, 2008) (order on
remand); Tex. Pub. Util. Comm’n, Application of AEP Tex. Cent. Co. for Auth. to Change Rates,
Docket No. 28840, 2005 WL 6472784 (2005) (order, findings of fact nos. 166-70).

                                                70
               Oncor argues that the ALJs and the Commission “misread” the evidence, confusing

the distinction between “funding triggers” (which depend on financial-performance measures) and

“payment triggers” (which depend merely on operational-performance measures). Oncor asserts

that financial triggers are utilized only to determine whether its employee-incentive plans are

funded at all, not whether the funds apportioned to the plans are actually distributed to employees.

According to Oncor, distribution of funds depends on whether certain operational goals, directly

benefitting ratepayers, are met.

               Witnesses for the Commission, Alliance, and TIEC testified to the contrary—that

at least some of Oncor’s employee-incentive compensation was tied to financial-performance

measures and that the portion based on financial criteria should be disallowed. Specifically, TIEC

urged that 30% of Oncor’s incentive-compensation payments made under the company’s incentive

plans should be disallowed because the performance metric (expressed as a percentage) is based

on financial goals.

               Oncor witness James A. Greer testified that payout under the company’s incentive

plans “is based on actual results compared with performance metrics” and that “[e]ach year a

scorecard is developed with specific performance metrics, such as safety, capital performance . . . and

reliability.” Oncor’s annual scorecard reflecting the performance metrics for incentive compensation

listed three goals: financial, reliability, and safety. Under the financial heading were listed “O&M

and System General and Administrative expense controls” and “capital performance expense controls.”

Each of these two financial measures was weighted at 15% of the total payouts. The ALJs agreed

with the opinions of witnesses for Commission staff, TIEC, and State Agencies that, as revealed by

the scorecard, 30% of incentive-compensation payments were directly tied to financial measures.

                                                  71
               The ALJs were not convinced by Oncor’s argument that the financial goals were

merely “funding triggers” as opposed to “payment triggers” and noted that if Oncor’s argument

were followed to its logical conclusion, then all of the incentive compensation Oncor sought (rather

than the $5 million reduction from the $19.5 million that it sought) should have been disallowed.

Additionally, as noted by the ALJs, various provisions in the incentive-plan documents support the

finding that the measures at issue are not operational but financial. For instance, the definition of

“performance goals” in the plan documents is defined as “financial, operational and/or individual

goals established as criteria to be achieved as a condition to the payment of Awards” (emphasis

added), and the terms “financial measure” and “operational measure” are independently used with

respect to award levels for each, signifying their distinct meanings. Oncor witness Greer testified

that the persons who prepared the scorecard would have been aware of the distinct meanings of

“financial” and “performance” as used in the plan documents.

               The evidence supporting the Commission’s decision amounts to more than a scintilla.

Although Oncor produced evidence that the $5 million in incentive-compensation payments

provided some benefit to the public, it was within the Commission’s fact-finding province to weigh

that testimony against the entirety of the evidence and find that Oncor had not met its burden of

proving that the incentive-compensation payments at issue were necessary to provide service to the

public. See id. We overrule Oncor’s fifth issue.


E.     Oncor’s reimbursement of municipalities’ regulatory expenses

               In its sixth issue, Oncor asserts that the Commission improperly denied recovery for

$0.6 million in payments Oncor made to Steering Committee to cover its consultants’ costs incurred

                                                 72
in appearing before the Commission and the Electric Reliability Council of Texas (ERCOT) to

address market-design issues. Oncor argues that the payments were reasonable operating expenses

and thus recoverable. The Commission responds that the payments were unnecessary because

Oncor voluntarily agreed to make them pursuant to a settlement agreement with Steering Committee

and that the payments were not proper “operating” or ratemaking expenses. Specifically, Oncor

challenges the Commission’s Finding of Fact Number 154, which reads: “Oncor’s payment of

$632,088 in cost paid to [Steering Committee] cities to reimburse them for their costs in appearing

before the Commission and ERCOT in various regulatory matters are not reasonable and necessary

operating expenses and cannot be recovered from ratepayers.”

               The resolution of this issue requires a factual determination of whether Oncor’s

expenses were “reasonable and necessary” because it was required to prove in the ratemaking

proceeding: “Only those expenses which are reasonable and necessary to provide service to the

public shall be included in allowable expenses.” 16 Tex. Admin. Code § 25.231(b) (also noting that

“[o]perations and maintenance expense incurred in furnishing normal electric utility service and in

maintaining electric utility plant used by and useful to the electric utility in providing such service

to the public” is specifically allowed category of expense subject to “reasonable and necessary”

requirement). The burden of proof to show that a utility’s expenses and requested rate change are

just and reasonable is on the electric utility. See PURA § 36.006; Houston Lighting & Power Co.,

778 S.W.2d at 198. Accordingly, the burden to show that the requested expenses were “reasonable

and necessary” was on Oncor.

               When reviewing the Commission’s fact findings, we use the deferential substantial-

evidence standard and cannot substitute our judgment for the Commission’s as to the weight

                                                  73
of the evidence. Public Util. Comm’n v. Gulf States Utils. Co., 809 S.W.2d 201, 211 (Tex. 1991);

City of Abilene v. Public Util. Comm’n, 146 S.W.3d 742, 748 (Tex. App.—Austin 2004, no pet.)

(“A court that is reviewing purely factual administrative findings . . . may determine only whether

substantial evidence supports those findings.”). The true test is not whether the agency reached the

correct conclusion (or the appellant’s desired conclusion) but whether some reasonable basis

exists in the record for the agency’s action. Charter Med., 665 S.W.2d at 452. We must presume

substantial evidence supports the Commission’s findings and conclusions, and the appellant has the

burden to prove otherwise. Id. at 453. Hence, if there is evidence to support either affirmative or

negative findings on a specific matter, the decision of the agency must be upheld even if the evidence

preponderates against it. Id.

               Oncor argues that the record contains no evidence explaining why these expenses

were not reasonable and necessary and that the only testimony disfavoring them was that of

Commission staff witness Mary Jacobs, who testified that the expenses did not fall under a particular

statutory allowance for consultants’ fees incurred in ratemaking proceedings, see PURA § 33.023(b),

but offered no opinion otherwise about their reasonableness and necessity. Oncor argues that the

issue is not whether the reimbursements qualified under section 33.023(b) as rate-case expenses but

whether they constituted reasonable and necessary operating expenses. We agree. However, it was

not the Commission’s burden to identify or produce evidence demonstrating that the municipal

payments were not reasonable and necessary. Rather, Oncor had the burden to prove that the payments

were reasonable and necessary.

               The settlement agreement at issue resolved a dispute between Oncor and Steering

Committee about whether Oncor’s rates should be lowered. Seeking to force Oncor to reduce its

                                                 74
rates, the various Steering Committee cities had filed show-cause hearings with the Commission.

The record is silent on the details of the dispute or negotiation process, but it does contain a copy of

the settlement agreement (and later modification thereof). One of the many concessions that Oncor

voluntarily made in the settlement agreement, in exchange for the cities’ abatement of their show-

cause hearings, was to “pay up to $40,000 per month through December 2009 to reimburse [Steering

Committee] for [its] involvement before ERCOT and the PUC concerning market design issues.”

It is these reimbursement payments, agreed to by Oncor in settling its rate disputes with Steering

Committee, that Oncor claims are reasonable and necessary operating expenses “incurred in

furnishing normal electric utility service.” See 16 Tex. Admin. Code § 25.231(b)(1)(A).

                To demonstrate the reasonableness and necessity of these reimbursements, Oncor

cites the testimony of its sole witness on the issue, Pruett, asserting that his testimony is uncontroverted

and compels a finding favorable to Oncor. Pruett testified that while the disputes between the cities

and Oncor “were primarily concerned with rates,” the settlement of those disputes “involved the

consideration of various operational items, such as improving communications . . . , discussion of

payment of franchise fees . . . , [and] the provision by Oncor of quarterly updates regarding capital

expenditures and affiliate transactions.” He continued, “it can be beneficial to both those cities and

Oncor if those cities are aware of, and able to participate with respect to, the changing environment

in which Oncor operates at ERCOT and the Commission.” Although Oncor suggests otherwise,

we do not find this testimony unequivocal. In fact, the settlement agreement speaks for itself, and

Pruett’s testimony adds little to the analysis except his implied conclusion that, because some of the

agreement’s provisions prescribe the terms of an ongoing working relationship between the cities

and Oncor, any expenses associated therewith are necessarily “operating expenses.”

                                                    75
                The provisions of and payments made under the settlement agreement as well as

Pruett’s interpretation of that agreement and opinion that the parties benefit by being involved in the

regulatory scene do not compel a finding that Oncor’s reimbursement of the cities’ consultant fees

in exchange for the cities’ agreement to abate their show-cause actions are operating expenses

“necessary to providing service to the public.” While it may have been beneficial to Oncor to avoid

show-cause hearings by entering into the settlement agreement, it does not necessarily follow that

the voluntarily made concessions therein are reasonable and necessary operating expenses of the

utility. Nor does it follow that measures taken (in the form of Oncor’s payment of the cities’ consultant

fees) to increase the cities’ “awareness of” and “participation in” the changing regulatory environment

constitute operating expenses of Oncor.35 Pruett’s lone statement that the settlement agreement

“involved consideration of various operational items” does not equate the reimbursements to

“operating expenses.” The Commission’s determination that Oncor had not met its burden to prove

that the reimbursements were “necessary” to provide service to the public was supported by

substantial evidence. Accordingly, we overrule Oncor’s sixth issue.


IV.     Non-ratemaking issue: direct-assignment-of-costs study

                Oncor’s seventh issue argues that the Commission abused its discretion in ordering

Oncor to prepare a study addressing the direct assignment of costs to wholesale customer classes for


        35
          Had Oncor altruistically offered to pay the cities’ consultant fees and received nothing in
exchange (except, perhaps, the hope of having good relations with the cities going forward), there
can be no question that such voluntary payments of expenses incurred by separate, unaffiliated
entities would not be, as a matter of law, reasonable and necessary operating expenses of the utility.
We do not see how the payment of these expenses under a settlement agreement, accompanied by
allegedly commensurate benefits, necessarily alters this fundamental premise, in the absence of
evidence proving that the payments were necessary to provide service to the public.

                                                   76
possible future consideration of Oncor’s rates related to those classes. Rather than claiming that the

Commission exceeded its authority by ordering the study, Oncor’s appeal attacks the Order on the

basis of the merits of direct assignment, claiming that such methodology of rate-setting runs afoul

of PURA because it is discriminatory, violates principles of comparability, and improperly relies on

factors unrelated to Oncor’s costs and its system. Because the methodology is statutorily proscribed,

its argument goes, the Commission’s Order requesting it to produce a study in accordance therewith

is arbitrary and capricious. The Commission responds that PURA specifically authorizes it to request

reports from utilities such as Oncor and that Oncor’s arguments about the propriety of direct

assignment—were the Commission to use such methodology in a future proceeding—are premature

because the Commission has not implemented rates based on direct assignment in this case and is

merely contemplating use of the methodology in the future.36

               The propriety of setting wholesale customers’ rates using the direct-assignment

methodology versus the “system average cost” methodology urged by Oncor is central to this dispute.

Using either methodology, the purpose is to determine the proper amount of distribution-plant

investment that should be allocated to wholesale customer classes.37 With direct assignment, the

distribution-plant investment is based on the specific cost of the facilities used by Oncor to provide

service to only the wholesale customers. With system-average cost, Oncor’s total distribution-plant

investment is allocated to its wholesale classes as well as its retail classes proportionally to each

       36
          Intervenors below, Tex-La Electric Cooperative of Texas, Inc. and Rayburn Country
Electric Cooperative, Inc., filed an appellate brief supporting the Commission’s position and
addressing the merits of the direct-assignment methodology.
       37
         Wholesale customers are those who purchase transmission and distribution service from
Oncor and then deliver and sell the power to their respective retail customers.

                                                 77
class’s non-coincident peak demand. The wholesale rates in effect at the time of Oncor’s filing of

its rate-change application had been derived using the direct-assignment methodology and had been

stipulated to by wholesale customers and Oncor’s predecessor in the course of settling their

disagreement about wholesale rates during that company’s previous ratemaking case. In the present

case, Oncor sought to increase the wholesale class rates by implementing the system-average-cost

methodology, which would have resulted in a significant increase in the wholesale customers’ rates.

Witnesses for Oncor and the intervenors offered conflicting testimony about the merits of using one

methodology over the other.

               In its Order, the Commission concluded that the evidence in this case was “inadequate

to set rates based on direct assignment” but noted that such methodology may be considered for

wholesale rate classes and is consistent with PURA and the Commission’s substantive rules.

Additionally, the Commission ordered Oncor to “perform a direct assignment study for the wholesale

classes and provide that study to the Commission in a[] future project to evaluate direct assignment

of costs for wholesale classes or for consideration to assign wholesale costs according to that study

in the next rate proceeding.” We first consider whether the Commission’s Order requiring Oncor

to perform the study exceeded the Commission’s authority or was otherwise in error.

               The Commission has express statutory authority to require “a public utility to report

to the commission information relating to . . . the utility.” PURA § 14.003(1)(A). Additionally, the

Commission has the 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.” Id. § 14.001. Although neither



                                                 78
of these statutes requires the Commission to explain or provide any justification for its request for

information, we note that the record contains substantial evidence to overcome Oncor’s assertion

that the Commission acted “arbitrarily and capriciously” in ordering the study. For instance, several

witnesses testified about the benefits of direct assignment, and the Commission’s Order noted its

determination in a previous docket that direct assignment is an appropriate, accurate, and fair

methodology. We conclude that the Commission acted well within its statutory authority in requiring

Oncor to prepare and provide the direct-assignment study and did not exercise that authority

arbitrarily and capriciously.

               Next, we consider Oncor’s arguments on the merits of the use of direct assignment

in setting wholesale rates. The Commission responds that Oncor’s attempt to engage this Court in

consideration of the merits is premature (i.e., the issue is unripe) because the Commission has not

yet decided to use that methodology in setting Oncor’s rates and is merely exploring the option by

requesting further information in the form of the study. We agree with the Commission. See City

of El Paso v. Public Util. Comm’n, 839 S.W.2d 895, 923 (Tex. App.—Austin 1992), rev’d in part

on other grounds, 883 S.W.2d 179 (Tex. 1994) (holding unripe appellant’s issue contending

that Commission failed to consider excess capacity of electric generating unit that was not yet

operational). The ripeness doctrine aims to conserve judicial time and resources for real and current

controversies, rather than abstract, hypothetical, or remote disputes. Patterson v. Planned Parenthood

of Houston & Se. Tex., Inc., 971 S.W.2d 439, 443 (Tex. 1998). It also protects state agencies from

judicial interference until an administrative decision has been formalized and its effects felt in a

concrete way by the challenging party. Id.



                                                 79
               The Commission has not mandated the use of direct-assignment methodology to set

Oncor’s rates in this proceeding or a future proceeding; instead, it has merely directed Oncor to

gather the relevant data and prepare a study presenting the information to the Commission, which

we have already determined was a proper exercise of its discretion.38 Thus, Oncor’s contentions that

the use of direct-assignment methodology in setting rates violates PURA are not ripe for review.39

Accordingly, we overrule Oncor’s seventh issue.


                                         CONCLUSION

               For the foregoing reasons, we reverse the district court’s judgment on the issues of

(1) the university discount; (2) franchise-fee expenses; (3) “lead days” for the franchise-tax

component of cash working capital; and (4) federal income-tax expense, and we remand these issues




       38
           Notably, the Commission amended the ALJs’ factual finding from “[d]irect assignment
of costs should be used for the wholesale rate classes” to “[d]irect assignment of costs may be
considered for wholesale rate classes” (emphasis added). This change signifies the limited nature
of its mandate that Oncor “maintain data adequate” for the direct assignment of costs and “prepare
a direct assignment study” and does not require that Oncor’s future rates be established using a
direct-assignment methodology.
       39
            Even if Oncor’s merits arguments were properly before us on review, Oncor has not
demonstrated that its substantial rights would be prejudiced by the Commission’s determination
that the direct-assignment methodology is consistent with PURA. See Tex. Gov’t Code § 2001.174
(reviewing court shall reverse or remand case “if substantial rights of the appellant have been
prejudiced because the administrative findings, inferences, conclusions, or decisions are . . . not
reasonably supported by substantial evidence [or affected by other specified deficiencies]”). The
only harm that Oncor has alleged is the “time and resources” that it must expend in preparing the
study. However, Oncor neither challenges the Commission’s finding that the difficulties associated
with direct assignment are “not particularly onerous or insurmountable” nor identifies evidence
supporting its alleged harm or showing that it is caused by the Commission’s findings on the merits
of the methodology.

                                                80
to the Commission for further proceedings consistent with this opinion. We affirm the district

court’s judgment in all other respects.



                                           __________________________________________

                                           David Puryear, Justice

Before Justices Puryear, Henson, and Goodwin
 Justice Henson not participating

Affirmed in Part; Reversed and Remanded in Part

Filed: August 6, 2014




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