State Agencies & Institutions of Higher Education v. Railroad Commission

TEXAS COURT OF APPEALS, THIRD DISTRICT, AT AUSTIN
NO. 03-13-00018-CV
The State of Texas Agencies and Institutions of Higher Education, Atmos Texas
Municipalities, City of Dallas, and Atmos Cities Steering Committee, Appellants
v.
Railroad Commission of Texas and Atmos Pipeline-Texas, Appellees
FROM THE DISTRICT COURT OF TRAVIS COUNTY, 53RD JUDICIAL DISTRICT
NO. D-1-GV-11-001240, HONORABLE STEPHEN YELENOSKY, JUDGE PRESIDING
OPINION
The State of Texas Agencies and Institutions of Higher Education (“the State
Agencies”), Atmos Texas Municipalities (“the Municipalities”), the City of Dallas (“the City”), and
Atmos Cities Steering Committee (“the Steering Committee”) appeal from a district-court judgment
in a suit for judicial review of the Texas Railroad Commission’s final order in a gas-utility rate case
conducted under the Gas Utility Regulatory Act (GURA), Tex. Util. Code §§ 101.001-105.051. The
district court affirmed the Commission’s final order. We will affirm the district court’s judgment.
See Administrative Procedure Act (APA), Tex. Gov’t Code § 2001.174(1).
FACTUAL AND PROCEDURAL BACKGROUND
Atmos Pipeline-Texas (“Atmos Pipeline”) filed a statement of intent to increase its
“Rate CGS” and “Rate PT” rates. “Rate CGS” is the tariffed rate Atmos Pipeline charges for
gas transportation and storage services provided to local distribution companies and other
city-gate-service customers.1 “Rate PT” is the tariffed rate Atmos Pipeline charges for interruptible
transportation services provided to certain on-system industrial customers whose rates are regulated
because they do not have viable competitive transportation alternatives to Atmos Pipeline.2 Atmos
Pipeline provides gas transportation services for both regulated and non-regulated customers. After
a contested-case hearing, the Commission found that Atmos Pipeline had established that its total
revenue requirement was $226,772,532.3 The Commission also found that Atmos Pipeline
established that the amount of revenue received from non-regulated customers (“Other Revenue”)
was $83,723,391.4 Rather than allocate any costs of service to the Other Revenue customer class,
Atmos Pipeline instead proposed to apply the Other Revenue it received as a credit against the total
revenue requirement. The Commission found that it was just and reasonable to do so and
consequently found that the adjusted revenue requirement was $143,049,141. The Commission then
set Rate CGS and Rate PT at levels that would allow for recovery of that amount.
Because it derives from negotiated rates in a competitive market, the amount of Other
Revenue received by Atmos Pipeline varies from year to year. In years in which Other Revenue
1
“CGS” is short for City Gate Service.
2
“PT” is short for Pipeline Transportation.
3
The final revenue requirement represents the total revenues needed by the utility to cover
its reasonable and necessary operating expenses and receive a reasonable return on the rate base. See
City of El Paso v. Public Util. Comm’n, 883 S.W.2d 179, 187 n.15 (Tex. 1994).
4
The “Other Revenue” class consists of certain industrial customers, electric generation
customers, gas producers, and marketer customers to whom Atmos Pipeline provides transportation
and storage services pursuant to negotiated, rather than regulated, rates.
2
actually received is less than the $83,723,391 received in the test year, the designated credit to the
total revenue requirement, if left unchanged, would exceed the amount of Other Revenue actually
received. In that event, Other Revenue plus revenue generated from the rates set by the Commission
would be less than the $226,772,532 total revenue requirement established in the rate-making
proceeding. Conversely, in years in which Other Revenue exceeded $83,723,391, the credit to the
total revenue requirement would be less than the amount of Other Revenue actually received. Other
Revenue plus revenue generated from the set rates would, in that case, amount to more than the
$226,772,532 total revenue requirement. In short, deviations from the $83,723,391 test-year amount
of Other Revenue would result in a credit to the total revenue requirement that would not match the
actual amount of Other Revenue. Thus, an Other Revenue credit that was a fixed amount would not
give ratepayers a larger credit in years in which Other Revenue exceeded the test-year amount and
would result in ratepayers receiving a credit greater than the actual amount of Other Revenue in years
in which that revenue stream fell below the test-year amount.5
To address this phenomenon and ensure that the Other Revenue credit more
accurately reflects the amount of Other Revenue actually generated in a particular year, Atmos
5
The Steering Committee introduced evidence of this feature of a fixed Other Revenue
credit in this rate-making proceeding. Specifically, in its brief the Steering Committee summarized
its evidence as showing that when the Other Revenue credit is set at a fixed amount, as it was in the
previous GUD Docket No. 9400, “ratepayers have not seen a corresponding benefit from [Atmos
Pipeline’s] increased revenues from competitive transactions.” According to the Steering
Committee’s evidence, the Atmos Pipeline system has seen increasing use by competitive customers
due to a significant rise in production of natural gas from the Barnett Shale formation. Steering
Committee witness Constance T. Cannady testified that because historically there was no “true-up”
or adjustment mechanism for the amount of Other Revenue established in the previous rate-making
proceeding (GUD Docket No. 9400),“[Atmos Pipeline] did not share the significant windfalls” from
increases in Other Revenue during the years 2004 through 2009.
3
Pipeline proposed an adjustment mechanism that would increase the capacity-charge component of
Rate CGS and Rate PT in years when Other Revenue actually received was below $83,723,391 and
decrease the capacity-charge component of Rate CGS and Rate PT in years when Other Revenue
actually received exceeded $83,723,391. The adjustment mechanism, applied annually, was
designed so that Atmos Pipeline would collect through Rate CGS and Rate PT 75% of any
downward deviation in Other Revenue from the $83,723,391 credit to the revenue requirement
established in the rate-making proceeding. When Other Revenue collected exceeded the
$83,723,391 level, the adjustment mechanism would require that Atmos Pipeline return to its
customers 75% of any upward deviation in Other Revenue from the $83,723,291 level. The
adjustment mechanism has no effect on the targeted total revenue requirement of $226,772,532
established in the rate-making proceeding. Atmos Pipeline referred to this adjustment mechanism
as “Rider Rev” and described it as “a new, revenue tracking mechanism that will adjust Rate CGS
and Rate PT annually for changes in the level of revenue received from [its] ‘Other Revenue’
customer class in the prior year.” The Commission approved implementation of Rider Rev on a
three-year trial basis, finding that it was a reasonable mechanism to provide an annual adjustment
to Rate CGS and Rate PT for 75% of the difference between the test-year amount of Other Revenue
established in the rate-making proceeding and the actual amount of Other Revenue determined on
an annual basis.
After the Commission issued its order and motions for rehearing were filed, the
Commission issued an order nunc pro tunc correcting some mathematical errors and denied the
motions for rehearing. Subsequent motions for rehearing were overruled by operation of law, and
4
several parties to the rate-making proceeding filed suits for judicial review in Travis County district
court. See GURA §§ 103.014, 105.001; APA § 2001.171. On the parties’ agreed motion, the suits
for judicial review were consolidated into one case. The district court affirmed the Commission’s
order, after which the State Agencies, the Municipalities, the City, and the Steering Committee
appealed the judgment. All of the appellants challenge the Commission’s approval of Rider Rev.
In addition, the Municipalities challenge the Commission’s return-on-equity determination; the
Steering Committee challenges the Commission’s decision to apply Other Revenue as a credit
against the total revenue requirement rather than establishing an “Other Revenue” rate class for
competitive customers; and the City challenges the Commission’s finding that a 2004 merger
between TXU Gas Company LP and Atmos Pipeline’s parent company, Atmos Energy Corporation,
was in the public interest. We will provide additional facts germane to the various points of error
throughout this opinion.
DISCUSSION
Treatment of the “Other Revenue” Customer Segment
In its first issue, the Steering Committee complains that the Commission erred by
applying Other Revenue generated from competitive customers’ use of the system as a credit against
the total revenue requirement without requiring an analysis of Atmos Pipeline’s specific cost of
serving those customers. According to the Steering Committee, the use of a credit—even a
fluctuating credit—does not accurately reflect and apportion the cost of providing services to the
unregulated customers. In the Steering Committee’s view, these customers should be treated like
the regulated customers and charged on a pure cost-of-service basis, rather than applying revenue
5
generated from their negotiated rates as a credit against the ratepayers’ revenue requirement
obligation. The Steering Committee argues that the Commission’s order in this regard is not
supported by substantial evidence and that its conclusion is therefore arbitrary and capricious and
results in the regulated customers essentially subsidizing the unregulated customers’ use of
the system.
We review the Commission’s decision in a rate-making proceeding to determine
whether it is supported by substantial evidence. CenterPoint Energy Entex v. Railroad Comm’n,
213 S.W.3d 364, 369 (Tex. App.—Austin 2006, no pet.). Under this standard we may not, with
respect to questions committed to its discretion, substitute our judgment on the weight of the
evidence for that of the Commission. APA § 2001.174. We must, however, reverse the
Commission’s order if it prejudices substantial rights because its findings, inferences, conclusions,
or decisions (1) violate a constitutional or statutory provision; (2) exceed the Commission’s statutory
authority; (3) were made through unlawful procedure; (4) were affected by other error of law; (5) are
not reasonably supported by substantial evidence considering the reliable and probative evidence in
the record as a whole; or (6) are arbitrary or capricious or characterized by an abuse of discretion or
a clearly unwarranted exercise of discretion. Id.
The Commission’s order is presumed to be valid, and it is supported by substantial
evidence if the evidence in its entirety is sufficient to allow reasonable minds to have reached the
conclusion the agency must have reached to justify the disputed action. Texas State Bd. of Dental
Exam’rs v. Sizemore, 759 S.W.2d 114, 116 (Tex. 1988). The evidence in the record may
preponderate against the agency’s decision yet still provide a reasonable basis for the decision and
6
thereby meet the substantial-evidence standard. Texas Health Facilities Comm’n v. Charter
Med.-Dallas, Inc., 665 S.W.2d 446, 452 (Tex. 1984). The party challenging the order has the burden
of demonstrating a lack of substantial evidence. CenterPoint Energy Entex, 213 S.W.3d at 369
(citing City of El Paso v. Public Util. Comm’n, 883 S.W.2d 179, 185 (Tex. 1994)).
Rates set by the Commission must be “just and reasonable,” “sufficient, equitable,
and consistent in application to each class of customer,” and not “unreasonably preferential,
prejudicial, or discriminatory.” GURA § 104.003(a). The supreme court has held that this type of
statutory language affords an agency “discretion to determine the method of rate design,” i.e., how
the utility’s revenue requirement is distributed among its various services. See Texas Alarm
& Signal Ass’n v. Public Util. Comm’n, 603 S.W.2d 766, 768 n.2, 772 (Tex. 1980). The
Commission is afforded considerable discretion regarding the factors to consider when addressing
the statutory rate considerations and the weight to be given those factors. See Nucor Steel v. Public
Util. Comm’n, 168 S.W.3d 260, 267-68 (Tex. App.—Austin 2005, no pet.). Rate design involves
complex technical, economic, and policy decisions that are appropriate for the Commission’s
“informed judgment and expertise.” Id. at 268.
The Steering Committee contends that some portion of the Atmos Pipeline system
was constructed for, and continues to be maintained for use by, the competitive customers. It also
maintains that the only way to accurately identify the true cost of service to the competitive
customers is through a thorough cost-of-service study. The Steering Committee asserts that without
such a study, it is impossible to know whether applying Other Revenue as a credit to the total
revenue requirement results in a fair assessment. According to the Steering Committee, evidence
7
that “throughput” from competitive customers has increased over time indicates that at least part of
the Atmos Pipeline system is being constructed and maintained for competitive customers’ use while
at the same time all the capital costs have been borne by the regulated customers. The Steering
Committee contends that, as a consequence, the regulated customers are required to unfairly
subsidize the competitive customers.
The Commission, however, made the following findings of fact, among others:
FOF 8: The Atmos Pipeline - Texas system is designed to meet the peak-day
demands of human needs [i.e., regulated] customers.
FOF 97: The fixed cost allocation as proposed in this case is just and reasonable:
The system is designed to satisfy the capacity requirements of the human needs
customers during peak demand; peak demand determines the amount of transmission
capacity and costs incurred by the company; and, no marginal or incremental costs
of capacity are incurred when additional volumes of gas are transported.
The Commission found that the plant was sized to meet the peak demands of the regulated customers
and therefore those customers should be responsible for paying for all of the pipeline system’s fixed
costs. These findings are supported by substantial evidence. Witnesses testified that no plant
capacity had ever been constructed or provided in the system for competitive customers, that the
system was sized to accommodate the peak demand of the regulated customer class, and that the
competitive customers were permitted to use the system only when there was available excess
off-peak capacity not being used by the regulated customers. The Commission heard evidence that
nearly all of the costs of the system are fixed and unrelated to the actual amount of throughput on
the system and that, as a consequence, an appropriate rate structure “should reflect the primacy of
fixed costs in both the cost allocation and rate design.” There was evidence presented that the
8
competitive customers’ use was interruptible and could be curtailed whenever necessary to meet the
capacity needs of the regulated customers. There was testimony that it was reasonable to use
revenue obtained from competitive customers’ use of the system as a credit to the utility’s total
revenue requirement to compensate for their temporary use, during off-peak periods, of capacity
designed for periods of peak demand.
We conclude that the Commission, in the exercise of its discretion to weigh the
factors bearing on the design of Atmos Pipeline’s rates, had a reasonable basis in the record for
concluding that most costs of the system were related to installing and maintaining facilities sized
to meet the peak needs of the regulated, non-interruptible, customers and that it was appropriate to
credit revenue received from the competitive customer’s use of the system’s available excess
off-peak capacity against the total revenue requirement assessed to the regulated customers in their
cost-of-service-based rates rather than establish a separate “Other Revenue” rate class. We overrule
the Steering Committee’s first issue.
Adoption of “Rider Rev”
Atmos Pipeline provides services both to regulated customers (charged pursuant to
Rate CGS and Rate PT) and to non-regulated customers (charged at negotiated rates). As previously
discussed, the revenue generated from the services provided to the non-regulated (or “competitive”)
customers is referred to as “Other Revenue” and has been applied as a credit against the total revenue
requirement set by the Commission in the rate-making proceeding. In this proceeding, the
Commission determined that Atmos Pipeline’s total revenue requirement was $226,772,532. The
Commission arrived at that number using the traditional cost-of-service method whereby the utility’s
9
total revenue requirement is set at an amount that includes a consideration of three central factors:
(1) the utility’s reasonable and necessary operating expenses; (2) the rate base;6 and (3) a reasonable
rate of return. See GURA §§ 103.021, 104.051-.058; see also Railroad Comm’n v. Entex, Inc.,
599 S.W.2d 292, 294 (Tex. 1980) (summarizing cost-of-service rate-making principles). The total
revenue requirement set by the Commission must be at a level that permits 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 its reasonable and necessary operating expenses.” GURA
§ 104.051; see also City of El Paso, 883 S.W.2d at 187 n.15 (revenue requirement is total revenues
utility needs to recover through its rates in order to cover its reasonable and necessary operating
expenses and receive return on rate base).
Here, the Commission heard evidence that Atmos Pipeline receives significant
revenues from non-regulated users of the pipeline system. Since its 2004 order in GUD Docket
No. 9400, the Commission has applied the revenues generated from Atmos Pipeline’s non-regulated
operations as a credit against the total revenue requirement established in the relevant test year. The
effect of this credit against the revenue requirement is to reduce the amount of money that must be
paid by regulated users of the pipeline system. The Commission set the credit at $83,723,391—the
amount of Other Revenue generated in the test year adjusted downward to take into account certain
post-test-year changes to Atmos Pipeline’s negotiated transportation, storage, and electric-generation
6
The rate-base calculation employs a balance between original cost, less depreciation, and
current reproduction cost, less an adjustment for age and condition. See GURA § 104.053(a). After
determining the rate base, the Commission determines the rate of return, which is “the percent of the
rate base which will be recoverable in revenues by the utility.” Railroad Comm’n v. Entex, Inc.,
599 S.W.2d 292, 294 (Tex. 1980).
10
agreements. Consequently, the amount to be collected from regulated customers through their rates
was reduced by that amount, for a total of $143,049,141.
The Commission agreed to implement Atmos Pipeline’s proposed rate design
whereby customer charges would be calculated as the product of a capacity charge and the
customer’s contract maximum daily quantity. Application of the Other Revenue credit reduces the
capacity-charge component of the rate for both the Rate CGS and the Rate PT, the tariffs applicable
to all Atmos Pipeline’s regulated customer classes.7
The Municipalities, the Steering Committee, the City, and the State Agencies each
raise numerous complaints regarding the Commission’s order adopting the adjustment mechanism
referred to as “Rider Rev” as part of the rate design in this proceeding. Rider Rev is an Other
Revenue tracking mechanism that adjusts the capacity-charge component of Rate CGS and Rate PT
annually in response to changes in the amount of Other Revenue received from year to year. The
mechanism compares deviations in Other Revenue in a given year from the $83,723,391 number
established in the rate-making proceeding and allocates 75% of that difference to the Rate CGS and
Rate PT tariffs. The allocation results in either an increase or a decrease in the capacity-charge
component of the tariffs for the next year. The purpose of Rider Rev is to adjust annually, either up
or down, the amount that regulated customers pay through their rates when the amount of Other
Revenue actually received in a given year deviates from the amount of the credit set in the
rate-making proceeding. Without the adjustment, changes in the amount of Other Revenue actually
7
The capacity charge for MMBtu of maximum daily quantity went from 6.2984 to 3.6263
for the Rate CGS customer class and from 4.0732 to 2.3601 for the Rate PT customer class.
11
received could result in the utility’s receiving total revenues (Other Revenues plus revenue received
from regulated customers through their rates) in an amount higher or lower than the established total
revenue requirement of $226,772,532. The adjustment ensures that the credit against the revenue
requirement enjoyed by the regulated customers more accurately reflects the amount of Other
Revenue actually generated in a given year.8 The Municipalities, the Steering Committee, the City,
and the State Agencies essentially argue that the Commission lacked authority to approve Rider Rev
and that it is in conflict with certain statutory provisions contained in GURA.
As an administrative agency, the Commission may exercise only those powers
conferred on it by the legislature in clear and express language. See Texas Natural Res.
Conservation Comm’n v. Lakeshore Util. Co., 164 S.W.3d 368, 377 (Tex. 2005); Public Util.
Comm’n v. City Pub. Serv. Bd., 53 S.W.3d 310, 316 (Tex. 2001). As a creature of the legislature,
an agency has no inherent authority of its own and may not create and exercise what really amounts
to a new or additional power for the purpose of administrative expediency. Lakeshore Util. Co.,
164 S.W.3d at 377. “When the Legislature expressly confers a power on an agency, it also impliedly
intends that the agency have whatever powers are reasonably necessary to fulfill its express functions
or duties.” Id. at 378. An agency may not, however, through the guise of implied powers, exercise
what is effectively a new power, or a power contrary to a statute, on the theory that such a power is
8
We observe that the adjustment is not a dollar-for-dollar offset as it only accounts for 75%
of any deviation from the $83,723,291 test-year Other Revenue figure. There was testimony that
permitting the utility to essentially “keep” 25% of any increase in Other Revenue would incentivize
it to maximize the amount of Other Revenue generated, which would ultimately inure to the benefit
of the regulated ratepayers by virtue of a downward adjustment of the capacity-charge component
of their tariffs.
12
expedient for administrative purposes. City of Austin v. Southwestern Bell Tel. Co., 92 S.W.3d 434,
441 (Tex. 2002).
Among other things, the Commission is expressly authorized to establish a gas
utility’s rates. GURA § 104.001(b). GURA defines the term “rate” as:
(A) any compensation, tariff, charge, fare, toll, rental, or classification that is
directly or indirectly demanded, observed, charged, or collected by a gas
utility for a service, product, or commodity described in the definition of gas
utility in this section; and
(B) a rule, regulation, practice, or contract affecting the compensation, tariff,
charge, fare, toll, rental, or classification.
Id. § 103.003(12). This Court has previously observed that GURA’s definition of the term “rate”
reflects the legislature’s recognition that a rate “may consist not merely of a fixed dollar amount but
may instead be a rule ‘affecting’ the charge, a term contemplating the use of variables.” See
CenterPoint Energy Entex v. Railroad Comm’n, 208 S.W.3d 608, 618 (Tex. App.—Austin 2006,
pet. dism’d). Thus, the statute authorizes the Commission to approve “formula rates” (rules that
affect the customer charge) so long as they do not conflict with GURA.
GURA provides that “a gas utility may not increase its rates unless the utility files a
statement of its intent with the regulatory authority . . . .” GURA § 104.102(a). None of the parties
to this appeal contends that section 104.102 requires that a statement of intent must be filed every
month whenever a customer’s bill is different from the month before. In fact, tariffed rates
contemplate that each customer will receive a monthly bill calculated in accordance with a tariff
approved by the Commission and that the charge to the customer reflected in the bill will change
13
from month to month. Formula rates, which by their nature result in changes in customer’s charges,
may, when adopted in a rate-making proceeding conducted pursuant to GURA subchapter C, be
applied without the need for the utility to file a statement of intent or for the Commission to conduct
a full-blown rate-making proceeding each time they operate to change a charge to a customer. The
adoption of formula rates requires recognizing that there are certain changes in customer charges that
may occur without the need for a full statement-of-intent rate case. In other words, not every change
in a customer charge is a change in a “rate” for purposes of GURA section 104.102(a). The question,
then, is whether the changes in customer charges resulting from application of the Rider Rev
adjustment mechanism are the type of change in “rates” that GURA section 104.102 mandates may
be done only through a full “statement of intent” rate case. We conclude they are not.
In setting a utility’s rates, the legislature has expressly charged the Commission with
“establish[ing] overall revenues at an amount that will permit the utility a reasonable opportunity to
earn a reasonable return on the utility’s invested capital used and useful in providing service to the
public in excess of its reasonable and necessary operating expenses.” GURA § 104.051. The
Commission then designs rates that will generate the revenue requirement. See Nucor Steel,
168 S.W.3d at 268 (“Rate design is the ‘distribution of the revenue requirements among the various
services’ provided by the utility.” (quoting Texas Alarm & Signal Ass’n, 603 S.W.2d at 768 n.2).9
9
“The distribution of the revenue requirements among the various services is called rate
design. Ordinarily a utility will determine its overall revenue requirements and will then set the tariff
or price for each class at a level which will achieve a fraction of the revenue requirements. The
resulting price schedule is called the rate structure or rate schedule. The rate structure as a whole
is intended to produce the overall revenue requirements of the utility.” Texas Alarm & Signal
Ass’n v. Public Util. Comm’n, 603 S.W.2d 766, 768 n.2 (Tex. 1980) (citing Paul J. Garfield
& Wallace F. Lovejoy, Public Utility Economics 45 (1964); Michael Little, Rate Design,
14
The rate-design process involves an exercise of the Commission’s “informed judgment and expertise
and utilizes projections and estimates in virtually all areas.” Public Util. Comm’n v. GTE-Southwest,
Inc., 901 S.W.2d 401, 411 (Tex. 1995); see also Southwestern Pub. Serv. Co. v. Public Util.
Comm’n, 962 S.W.2d 207, 214 (Tex. 1998) (it is logical for Commission to have discretion over rate
design based on complexity of issues and procedures). “An administrative agency is created to
centralize expertise in a certain regulatory area and, thus, is to be given a large degree of latitude by
the courts in the methods by which it accomplishes its regulatory function.” GTE-Southwest,
901 S.W.2d at 409 (quoting City of Corpus Christi v. Public Util. Comm’n, 592 S.W.2d 290, 297
(Tex. 1978)). GURA’s silence in regard to this aspect of rate design demonstrates the legislature’s
intent to leave that decision within the Commission’s discretion. See Reliant Energy, Inc. v. Public
Util. Comm’n, 153 S.W.3d 174, 189 (Tex. App.—Austin 2004, pet. denied) (observing that
Commission has broad powers and discretion in regulating public utilities and holding that
legislature’s failure to specify when during forecasted test-year investments must occur to be
included in rate base manifested its intent to leave that decision to Commission’s discretion).
In this proceeding the Commission established the revenue requirement using the
traditional cost-of-service methodology. The revenue requirement it arrived at through this process
was $226,772,532. The Commission did not allocate any of this revenue requirement directly to the
non-regulated users of the system but chose instead to account for their use of the system by applying
Other Revenue as a credit against the revenue requirement, thereby reducing the amount of money
collected from regulated customers through Rate CGS and Rate PT. Because the Commission
28 Baylor L. Rev. 1083 (1976)).
15
applied Other Revenue of $83,723,291 as a credit against the $226,772,532 revenue requirement
before the rates were calculated, the capacity-charge components of both Rate CGS and Rate PT
were set from the outset at a level that would generate less than $226,772,532. The difference was
made up with Other Revenue. In the event Other Revenue actually received in a particular year is
less than $83,723,791 and the amount of the credit is not adjusted, however, the rates received from
the regulated users plus Other Revenue obviously will not equal the revenue requirement established
by the Commission in this rate-making proceeding. There was evidence that the Other Revenue
amount fluctuates from year to year because it derives from a competitive market. Rider Rev tracks
the actual amount of Other Revenue received and adjusts the capacity-charge component of Rate
CGS and Rate PT, either upward or downward, so that the utility has a reasonable opportunity to
receive its revenue requirement. Rider Rev therefore assists in accomplishing the Commission’s
objective of setting rates at a level that will generate revenue for the utility sufficient to give it a
reasonable opportunity to earn a reasonable return. See GURA § 104.051. Rider Rev also ensures
that, in the event Other Revenues exceed $83,723,791, regulated customers benefit from the extra
revenue through a reduced capacity charge. Implementing the adjustment mechanism was within
the Commission’s discretion to create a rate design that meets the regulatory goal of effectively
yielding the total revenue requirement established through a cost-of-service analysis. See Michael
Little, Rate Design, 28 Baylor L. Rev. 1083 (1976) (effectiveness in yielding total revenue
requirements under fair-return standard is attribute of desirable rate design).
But the Commission’s discretion is not unbridled. It does not, for example, have the
authority to implement a rate design that conflicts with GURA. See APA § 2001.174 (Commission’s
16
order must be reversed if it exceeds Commission’s statutory authority); City of Austin, 92 S.W.3d
at 441 (agency may not exercise what is effectively power contrary to statute). Appellants contend
that Rider Rev is contrary to GURA because it constitutes piecemeal rate-making. Piecemeal
rate-making occurs when isolated elements of the cost-of-service calculation are adjusted to the
exclusion of others in violation of GURA’s comprehensive cost-of-service rate-making analysis.
See GURA §§ 104.051 (requiring the regulatory authority to “establish the utility’s overall revenues);
.053 (prescribing method for calculating adjusted value of invested capital); .055 (prescribing
calculation of net income). But Rider Rev does not make adjustments to any of the components of
the cost-of-service calculation that the Commission used to determine the utility’s total revenue
requirement in the rate-making proceeding. It merely increases or decreases the capacity-charge
component of the rate to ensure that the credit to regulated customers against their fixed
revenue-requirement obligation reflects, to a reasonably accurate degree, the amount of Other
Revenue actually generated in a particular year. Rider Rev adjusts only the amount of an offset to
the revenue requirement; it makes no adjustments to any of the inputs used in the cost-of-service
calculation. Nor does it alter the total revenue requirement, which remains fixed at $226,772,532.
As such, Rider Rev does not make any changes to the basic elements of the rate and does not
function as a rate-making process. We conclude that an increase in the capacity-charge component
of Rate CGS and Rate PT that results from the Rider Rev adjustment mechanism operating to reduce
a credit against the total revenue requirement set in the rate-making proceeding does not constitute
the type of increase in “rates” that requires the filing of a statement of intent with the Commission.
See id. § 104.102.
17
Although Rider Rev might be characterized as a “formula rate,” the fact that it makes
no adjustment to any of the inputs in the original cost-of-service calculation distinguishes it from
other formula rates. For example, it is different from the adjustment mechanism authorized by the
“GRIP statute.”10 See id. § 104.301. The GRIP statute permits a gas utility to file a new tariff
adjusting its base rates to recover the costs of new capital investment made in the preceding
calendar year without the necessity of filing a rate case. See Atmos Energy Corp. v. City of Allen,
353 S.W.3d 156, 156 (Tex. 2011). GRIP expressly authorizes interim increases in rates to address
changes in the value of invested capital from year to year and allows a utility to recover the costs of
changes in the investment in service for gas utility services, which is essentially a change in the
overall revenue requirement. Capital investment is a component of the cost-of-service calculation,
and a change in rates resulting from the utility’s recovery of capital investment costs is the type of
“rate” increase that could, in the absence of the GRIP amendment, be done only through a full
statement-of-intent rate-making proceeding.
Rider Rev is likewise distinguishable from a cost-of-service adjustment (COSA)
clause, a type of formula rate recently addressed by this Court. See Railroad Comm’n v. Texas Coast
Utils. Coal., 357 S.W.3d 731, 745 (Tex. App.—Austin 2011, pet. granted). Unlike COSA, Rider
Rev does not adjust rates “to reflect changes in the utility’s actual cost of service and rate base
relative to the historically-based data from which the fixed components of those rates had originally
been derived.” See id. at 735 (describing COSA).
10
“GRIP” is an acronym for “Gas Reliability Infrastructure Program.” GURA section
104.301 is referred to as the “GRIP statute” or “GRIP amendment” even though the term does not
appear in the statute or applicable administrative rules.
18
We also disagree with appellants’ contention that Rider Rev violates GURA by
guaranteeing Atmos Pipeline a certain amount of profit while GURA only authorizes the
Commission to give a utility the opportunity to earn a fair return above its reasonable and necessary
expenses. See GURA § 104.051. Rider Rev does not guarantee that the utility will actually earn the
fair return the Commission found it would have the opportunity to earn if it received a total revenue
of $226,772,532. Instead, Rider Rev ensures only that the utility receives at or near the total revenue
requirement necessary for it to have the opportunity to recover the reasonable return approved in the
rate-making proceeding. Fixed revenues do not equate to fixed profits. Whether the utility actually
achieves the reasonable return depends on how closely the operating and other costs match those
used to establish the revenue requirement. Earning the reasonable return will still require proper
organization, efficient management, and economical operation by the utility. Even with Rider Rev,
Atmos Pipeline could fail to earn that reasonable return. Rider Rev therefore does not conflict with
GURA’s mandate that the Commission set rates at a level that permits the utility a reasonable
opportunity to earn a reasonable return.
We conclude that the Commission had the authority to approve Rider Rev, an
adjustment mechanism that effects no changes to the revenue requirement established in a full
cost-of-service rate-making proceeding as provided by GURA subchapter B and conducted
in accordance with GURA subchapter C. The Commission had the authority to adopt this
adjustment mechanism to keep track of and adjust the amount of a credit to the ratepayers’ total
revenue-requirement obligation to ensure that the credit approximated the amount of Other Revenue
actually received in a given year. We also conclude that Rider Rev does not conflict with GURA
19
because an increase in the capacity-charge component of Rate CGS and Rate PT that could result
from application of Rider Rev is not the type of change in a customer charge that requires the
Commission to conduct a full-blown statement-of-intent rate-making proceeding. Consequently, we
overrule the Municipalities’ second issue, the Steering Committee’s second issue to the extent it
contends the Commission did not have the authority to adopt Rider Rev, the City’s first issue, and
the State Agencies’ first issue.
Rider Rev/Substantial evidence and procedural due process
The Municipalities and the Steering Committee also complain that the form of Rider
Rev adopted by the Commission is not supported by substantial evidence and was approved in
violation of the APA. As adopted, Rider Rev incorporated certain modifications recommended by
the Examiners in the PFD. The Examiners recommended adopting Rider Rev if it was revised to:
• Specify the method of allocation of Rider Rev to customer classes.
• Extend the review period for Rider Rev from 30 to 60 days.
• Provide for Commission denial of a proposed Rider Rev adjustment and
provide the utility with a right to appeal from such a denial.
• Add more detail regarding the Other Revenue calculation.
• Require Atmos Pipeline to provide notice of Rider Rev adjustments to
customers.
• Provide for discovery regarding any proposed adjustment.
• Provide for cost recovery associated with Commission review.
• Provide for a three-year trial period with the requirement that Atmos Pipeline
request an extension supported by documentation regarding how Rate CGS
20
and Rate PT customers have benefitted from Rider Rev, volumes and
revenues for each of the three periods, customers gained or lost, and
customers shifted from Rate PT to Other Revenue and from Other Revenue
to Rate PT.
These additions to Rider Rev were derived primarily from suggestions made by Staff witness
Lynne M. LeMon. As suggested, the form of Rider Rev adopted by the Commission included a
detailed adjustment review process requiring Atmos Pipeline to file a report showing, among other
things, the actual amount of Other Revenue billed during the previous year, listing the customers in
the Other Revenue class, and stating whether the proposed adjustment would generate additional
revenue of more than 2.5% of Atmos Pipeline’s annual revenue for the previous year. Additionally,
Atmos Pipeline was required to notify affected customers within 30 days of the date of filing the
report and advise them of where they could inspect a copy of the filing. As approved, Rider Rev
provides the Commission and directly affected customers an opportunity to review the report and
submit discovery requests until the 40th day following the filing of the report. The Commission is
required to notify Atmos Pipeline of its decision to approve, deny, or adjust the proposed Other
Revenue adjustment on or before the 10th day before November 1st of the current year. Atmos
Pipeline has a right to appeal the Commission’s decision by filing a motion for rehearing within
20 days following issuance of the Commission’s decision. As approved, Rider Rev provides that
it will expire on the fourth November 1st following its effective date unless an extension for an
additional three-year period is approved by the Commission. In order to obtain an extension, Atmos
Pipeline must file a request that includes a statement of how Rate CGS and Rate PT customers have
21
benefitted from the use of Rider Rev. The mechanics of the Rider Rev adjustment were approved
in the same form as proposed by Atmos Pipeline and as fully litigated in the rate-making proceeding.
The Municipalities and the Steering Committee assert that because the form of Rider
Rev ultimately adopted by the Commission was filed by Atmos Pipeline after the Examiners issued
their PFD and in response to the Examiners’ request that Atmos Pipeline file a revised Rider Rev
reflecting their suggested recommendations for procedural additions to Rider Rev, they were denied
a full and fair hearing on disputed fact issues in violation of their statutory rights in a contested case.
In essence, the Municipalities and the Steering Committee argue that the addition of several
procedural requirements to the Rider Rev amounted to the creation of a new tariff that they did not
have the opportunity to review during the contested-case hearing. We disagree. The record contains
extensive testimony regarding how Rider Rev would be used in making adjustments to the
capacity-charge components of Rate CGS and Rate PT. The Rider Rev adjustment mechanism
adopted by the Commission is exactly as proposed by Atmos Pipeline, and its effect on Rate CGS
and Rate PT was fully examined in the rate-making proceeding.
The post-PFD additions to Rider Rev were procedural in nature, were designed to
protect the regulated customers, and were supported by the testimony of Staff witness LeMon, who
testified regarding certain shortcomings to the form of Rider Rev as proposed by Atmos Pipeline.
LeMon testified that if the Commission determined that Rider Rev was authorized by GURA, certain
amendments should be made to the form of the rider proposed by Atmos Pipeline. Specifically,
LeMon testified that the Commission should consider approving Rider Rev on a trial basis for two
years. She recommended that after the first year the Gas Service Division should provide the
22
Commission with an evaluation of the Rider Rev so that the Commission could determine whether
to extend its effective date. If the Commission did not expressly extend the effective date, it should
be allowed to expire. LeMon further recommended that, as with interim adjustments made pursuant
to the GRIP statute, the utility should be required to explain why its rates are not unreasonable or in
violation of the law if the return on invested capital exceeds the approved level by more than 75 basis
points. LeMon also testified that Atmos Pipeline should be required to identify in the tariff how
proportional allocations would be made when calculating Rider Rev adjustments. The inclusion of
notice provisions is supported by LeMon’s testimony that Rider Rev, as proposed, was procedurally
flawed because it failed to include such provisions. The record contains no testimony approving or
disapproving of LeMon’s suggestions or any cross-examination regarding her suggestions.
The substantive aspects of Rider Rev, as adopted by the Commission, were fully
reviewed in a contested-case hearing, during which witnesses were permitted to, and did, present
testimony both in favor of and opposed to the adjustment mechanism. Moreover, there was
testimony regarding additional procedural requirements recommended for inclusion in Rider Rev,
and all parties had the opportunity to present additional testimony in that regard or to challenge the
testimony provided. Thus, the procedural aspects of Rider Rev were a subject of the contested-case
hearing. We conclude that the Commission’s adoption of Rider Rev did not violate the procedural
requirements of the APA and that it is supported by substantial evidence. We overrule the
Municipalities’ third and fourth appellate issues and the Steering Committee’s second issue to the
extent it contends that Rider Rev, as approved, is not supported by substantial evidence.
23
Return on Equity
In its first point of error, the Municipalities complain that the Commission improperly
based its return-on-equity (ROE) determination on proxy companies that were not similar to Atmos
Pipeline and did not share corresponding risks. The Municipalities contend that by doing so, the
Commission did not “properly implement the law,” which requires that a utility’s return on equity
be consistent with the return on capital investments generally being made at the same time and in
the same general part of the country by businesses with similar risks. See Bluefield Waterworks
& Improvement Co. v. Public Serv. Comm’n, 262 U.S. 679 (1923). The Commission is charged with
setting a return on equity that corresponds to the amount of risk a utility faces. In the present case,
Atmos Pipeline advocated setting the rate of return using the Discounted Cash Flow (DCF) model
and assessing the reasonableness of the resulting ROE using the Capital Asset Pricing Model. The
Commission found that it was reasonable to use the DCF model to determine the appropriate ROE,
a finding the Municipalities do not challenge.
In the case of a non-publicly traded utility such as Atmos Pipeline, an analyst must
use data from a proxy group to perform the DCF analysis. The DCF analysis is based on the theory
that a stock’s current price represents the present value of all expected future cash flows. It
essentially expresses the cost of equity, one component of the ROE calculation, as the sum of the
expected dividend yield and long-term growth rate. The DCF approach, however, requires real
market inputs that are not available for non-publicly traded companies. Consequently, the analyst
uses, as a proxy for those inputs, market information from a group of companies with a risk profile
and characteristics similar to that of the utility—the “proxy group.” See Petal Gas Storage
24
v. Federal Energy Regulatory Comm’n, 496 F.3d 695, 699 (D.C. Cir. 2007) (observing that proxy
groups provide market-determined stock and dividend figures from public companies comparable
to target company for which those figures are unavailable). The Commission found that it was
reasonable to use a proxy group of companies similar to Atmos Pipeline in the pipeline transmission
business to determine a return on equity. While the Municipalities do not dispute that the use of a
proxy group is reasonable, they assert that the companies comprising that proxy group have “very
different risks and uncertainties than [Atmos Pipeline] faces.” The issue, then, is whether the return
on equity adopted by the Commission was based on information from a proxy group composed of
companies having risks reasonably corresponding to those of Atmos Pipeline. The Municipalities
maintain this presents a legal question that we review de novo. We disagree. The composition of
the proposed proxy groups was determined by the expert witnesses who performed the DCF analysis
and testified before the Commission. The Commission was permitted to accept the use of a
particular proxy group if there is substantial evidence in the record that the members of the proxy
group had business models and risk profiles reasonably similar to those of Atmos Pipeline.
The Commission adopted an ROE of 11.80%, which was the ROE recommended by
the Commission Staff using a DCF analysis and a proxy group composed of eight companies. The
Staff’s and Atmos Pipeline’s proxy groups included six of the same companies. Atmos Pipeline’s
proxy group also included Spectra Energy Corporation and TC Pipelines L.P., while the Staff’s
proxy group also included Oneok Partners and El Paso Pipeline Partners. Frank Tomicek, an
economist appearing on behalf of the Staff, testified that he agreed that all companies included in
the Atmos Pipeline proxy group met appropriate criteria, and that he would not expect that having
25
two different companies in the composition of that proxy group would significantly impact the
modeling results. The Staff and Atmos Pipeline, then, were essentially in agreement regarding which
companies were appropriately included in the proxy group.
Robert Hevert, the analyst appearing on behalf of Atmos Pipeline, testified that he
reviewed Atmos Pipeline’s financial and operational characteristics and then developed a set of
criteria to apply to other entities to develop a group of comparable companies for the proxy group.
Hevert noted that Atmos Pipeline is an intrastate natural gas pipeline company that provides
throughput services to third parties and transports gas to the Atmos Mid-Tex distribution division,
other local distribution companies, and industrial customers. The pool from which the
proxy companies were identified consisted of companies that, like Atmos Pipeline, own
cost-of-service-regulated pipeline assets and companies classified as diversified natural gas
companies or companies in the oil and gas segment. From this pool Hevert excluded companies that
(1) were not publicly traded; (2) did not pay dividends; (3) had less than 40% of total net operating
costs derived from, or assets associated with, regulated natural gas pipeline operations; or (4) had
a credit rating below Standard & Poor’s BBB-. Hevert also included companies that had significant
natural gas pipeline operations and owned major Texas interstate natural gas pipelines. Hevert
testified that he was careful to include only companies that were primarily regulated natural gas
transmission companies. Hevert used these criteria because, in his opinion, natural gas transmission
operations are considered riskier than natural gas distribution companies and appropriately mirrored
Atmos Pipeline’s risk profile.
26
Tomicek testified that the Staff used a proxy group of natural gas transmission
companies engaged in similar business operations and with comparable business risk levels to Atmos
Pipeline in order to comport with the requirement that a utility be allowed the opportunity to earn
a rate of return commensurate with other businesses having comparable risk. The Staff’s proxy
group was chosen to include pipeline companies that were engaged primarily in regulated natural
gas pipeline transmission operations, had some operational assets in Texas, had publicly traded
shares, had financial analyst coverage, paid regular dividends, and had stable credit ratings. The two
companies in Tomicek’s proxy group that differed from those in Hevert’s proxy group were
companies that owned and operated natural gas transportation pipelines, storage, and other
midstream assets. Like Hevert, Tomicek testified that the members of his proxy group had financial
and operational-risks similar to those of Atmos Pipeline.
The Municipalities assert that the proxy group members are not comparable because
Atmos Pipeline is a division of a larger company, Atmos Energy, and there was “a significant
disconnect between [Atmos Pipeline’s] risks and those of the interstate pipeline companies” in the
proxy group. But Tomicek testified that, although Atmos Pipeline was smaller than the proxy
companies and is a division of a company with a different scope of operations from an interstate
pipeline company, the use of the proxy companies was appropriate because they were engaged in
similar business operations and reflected financial operating characteristics similar to pipeline
transportation operations. The Municipalities also argue that most of the proxy companies are
master limited partnerships, a corporate structure different from Atmos Pipeline’s. This potential
concern was addressed by Hevert, who testified that the inclusion of master limited partnerships was
27
necessary because many corporate pipeline companies are being reorganized into master limited
partnerships, thereby diminishing the number of publicly traded dividend-paying corporations with
significant natural gas pipeline operations from which to construct a proxy group. Hevert testified
that the master limited partnerships met his screening criteria and face the same business and
operating risks as Atmos Pipeline. In his view there was no reason to believe that the form of
organization would have any effect on these fundamental values. Moreover, because the master
limited partnerships pay cash distributions and are followed by analysts who provide growth
projections, they can be analyzed using the DCF model. Finally, to the extent the Municipalities
contend that it would be more appropriate to have a proxy group consisting of local distribution
companies rather than pipeline transmission companies, Hevert testified that local distribution
companies should not be part of the proxy group because they have significantly different risk
profiles from companies engaged in pipeline operations; in particular, they are subject to competition
from other pipeline companies for their non-regulated customers. While acknowledging that Atmos
Pipeline does significant business with an affiliated local distribution company, Hevert noted that
a large portion of revenue comes from transmission service provided to non-regulated competitive
customers. He stated that the investment community distinguishes between pipeline transmission
companies and local distribution companies because of their differing operational-risk profiles.
We conclude that there was substantial evidence supporting the propriety of the proxy
group Tomicek used to perform the DCF analysis that led him to advocate for an 11.80% ROE. The
evidence in its entirety was sufficient to allow reasonable minds to have reached the conclusion that
the proxy group was composed of companies facing operational and financial risks reasonably
28
commensurate with those of Atmos Pipeline and could be used to perform the DCF analysis needed
to identify an appropriate ROE for the utility here.
The Municipalities also contend that the Commission departed from existing
precedent in setting Atmos Pipeline’s ROE without adequately explaining this departure. The
Municipalities note that in 2004, TXU Energy, predecessor-in-interest to Atmos Pipeline’s parent
company Atmos Energy Corporation, filed a statement of intent to change rates in its statewide gas
utility system, including both its distribution and pipeline divisions, which was docketed as GUD
Docket No. 9400. In that proceeding, the Commission assigned a 10% ROE for the entire company
using a proxy group made up of local distribution companies. The Commission, asked to set an ROE
for the company as a whole, set the ROE based on the evidence presented in that case, which
reflected market information existing at the time. The Municipalities argue that by doing so the
Commission adopted a precedent that the divisions of a company may not obtain a ROE different
from the parent company.
We disagree that there is any such stated or implicit Commission precedent. As an
initial matter, we note that the Commission had, prior to GUD Docket No. 9400, set different ROEs
for TXU Energy’s pipeline and distribution divisions. See GUD Docket No. 8976 (setting pipeline
company’s ROE at 11%); GUD Docket No. 9145 (setting distribution company’s ROE at 12.1%).
Moreover, the Commission has regularly assigned individual ROEs to divisions of larger companies
based on their particular business operations and attendant risks. For example, CenterPoint Energy
Entex’s Texas Coast, Houston, South Texas, and Beaumont East Texas divisions have been assigned
different ROEs in four separate proceedings. See GUD Docket Nos. 9791, 9902, 10038, and 10182.
29
Similarly, Texas Gas Service Company’s Rio Grande Valley, El Paso, North Texas, and South Texas
divisions have obtained different ROEs in four separate proceedings. See GUD Docket Nos. 9708,
9988, 10094, and 10217. It is simply not the case that the Commission has adopted any rule or
created any precedent that different divisions of a company must all have the same ROE.
Rather, it appears that the Commission’s only “precedent” is to consider the utility’s
specific request in each docket and assign an appropriate ROE based on the evidence presented. In
the present case, in contrast to GUD Docket No. 9400 but consonant with GUD Docket No. 8976,
the utility asked for an ROE to be set for the pipeline transportation division of the parent company.
As previously discussed, substantial evidence supported the proxy group used by the Commission
to set the ROE for Atmos Pipeline, and there have been no other challenges to the methodology the
Commission used to arrive at this ROE. If the Municipalities’ contention is that Atmos Pipeline’s
ROE should be set at 10% simply because that is the ROE established at a rate-making proceeding
that took place in 2004, we observe that this would deviate from the holdings in Bluefield and
Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591 (1944), which establish that the
Commission is required to consider and evaluate the utility’s current operations and risk to ensure
returns expected elsewhere in the current market for investments of equivalent risk. See Bluefield,
262 U.S. at 692 (public utility entitled to rates that permit it to earn return equal to that generally
being made at same time and in same general part of country on investments in other undertakings
with corresponding risks and uncertainties); Hope, 320 U.S. at 603 (return to equity owner should
be commensurate with returns on investments in other enterprises having corresponding risks).
Moreover, to the extent the Municipalities’ argument is that the Commission was required to explain
30
why it was assigning a different ROE to the pipeline transmission division than to the local
distribution division of the utility as a whole, it has done so. The Commission expressly found that
it was reasonable to use a proxy group of pipeline transmission companies. Substantial evidence,
including Hevert’s testimony regarding the different risk pools of the two types of business
operations, supports this finding. The Commission did not deviate from precedent by setting an
ROE for Atmos Pipeline based on a DCF analysis using a proxy group of companies with similar
operational and financial risks as Atmos Pipeline. We overrule the Municipalities’ first issue.
Best-Interest Finding Regarding Merger
In its second issue, the City contends that the district court erroneously affirmed the
portion of the Commission’s final order that found that the 2004 merger between Atmos Energy
Corporation (“Atmos Energy”) and TXU Gas Company, LP (TXU Gas) was in the public interest.
In 2004 Atmos Energy acquired, by merger, TXU Gas, including both its distribution assets and its
pipeline and storage assets. After the merger, Atmos Energy formed two divisions: (1) Atmos
Energy Mid-Tex Division, which now holds the acquired distribution assets, and (2) Atmos Pipeline,
which now holds the acquired pipeline and storage assets. When the merger was completed, Atmos
Energy gave the Commission notice of the merger as required by GURA. See GURA
§ 102.051(a)(2) (gas utility must report to Commission merger or consolidation with another gas
utility operating in this state). Once it receives notice of a merger or consolidation, the Commission
must investigate the transaction, with or without a public hearing, to determine whether the action
is consistent with the public interest. Id. § 102.051(b). The Commission must consider “the
reasonable value of the property, facilities, or securities to be . . . merged or consolidated.” Id. If
31
the Commission finds that a transaction is not in the public interest, it must take the effect of the
transaction into consideration in rate-making proceedings and disallow the effect of the transaction
if it will unreasonably affect rates or services. Id. § 102.051(c).
The Commission docketed the notice of the merger between Atmos Energy and TXU
Gas as GUD Docket No. 9555, which it styled Application for Review of Merger Between Atmos
Energy Corporation and TXU Gas Company Ltd. The Commission Staff then sent Atmos Energy
a set of Requests for Information to gather information regarding the terms of the merger. The
Requests sought information regarding the nature and location of the assets transferred by the
merger, the total sales price of the transferred property, and the method of payment. The Staff also
requested information regarding the value of any intangible assets transferred, such as tax credits and
deferred taxes. The Staff requested that Atmos Energy provide the final value of the amount of
undepreciated original cost and accumulated depreciation of the property transferred in the merger.
The Staff inquired as to the impact of the transfer of property on the rates and services of former
TXU Gas customers and whether any customers or class of customers would be adversely impacted
by the merger. In verified answers Atmos Energy not only responded to those requests but also
stated that no adverse impact would result from the merger because essentially all of TXU Gas’s
operational employees were retained by Atmos Energy and they would ensure that service to
customers was maintained. Atmos Energy also responded that customer rates would not change as
a direct result of the merger. Atmos Energy provided the Staff with a copy of the Agreement and
Plan of Merger by which the transaction was completed. Atmos Energy also stated that:
32
The acquisition is consistent with the public interest for a number of reasons. It is
a combination of two entities with complementary strengths whose focus is entirely
on natural gas which will enable [Atmos Energy] to fully meet the needs of
customers and the communities it serves. Further, the manner of providing service
to customers will remain largely unchanged and there will be no reduced level of
service or reliability to customers. In addition, as noted in response to Staff RFI
Set 1, Question No. 1-13, there will be no change in rates as a direct result of the
acquisition. Therefore, the transaction will not unreasonably affect rates or services.
The Commission did not make any findings or issue a final order in GUD Docket No. 9555. Rather,
the Commission deferred consideration of whether the merger transaction was in the public interest
to a later proceeding.11 The Commission’s later decision regarding whether or not the merger was
in the public interest would, however, be informed by the information provided in response to Staff’s
Request for Information in GUD Docket No. 9555.
In May 2006, Atmos Mid-Tex, the division of Atmos Energy that held the company’s
distribution assets, filed a statement of intent to change its rates with the Commission. This filing
was docketed as GUD Docket No. 9670. As part of that proceeding, Atmos Mid-Tex submitted
testimony that the merger between TXU Gas and Atmos Energy was consistent with the public
interest because, despite some adverse tax consequences resulting from the form of the merger,
customers would benefit because natural gas service after the merger would be provided by a
corporation that is singularly focused on the gas utility business whereas before, TXU Gas’s parent
11
Deferring the public-interest conclusion to a later rate-making proceeding was logical in
this case because no further action would be required if the Commission concluded that the merger
was in the public interest; on the other hand, if the Commission concluded that the merger was not
in the public interest, it would be required to “take the effect of the transaction into consideration in
rate-making proceedings and disallow the effect of the transaction if the transaction will
unreasonably affect rates or services.” GURA § 102.051(c).
33
company was focused on several different aspects of the energy market. Moreover, Atmos Mid-Tex
had committed to invest in significant capital improvements to enhance safety and reliability.
Finally, Atmos Mid-Tex had reversed the decision of TXU Gas to outsource certain customer service
functions and identified various potential cost savings. In GUD Docket No. 9760, the Examiners
found that the safety, reliability, and quality of the natural gas service had not been affected by the
merger between Atmos Energy and TXU Gas and, in that regard, that the merger was consistent with
the public interest. But because of the impact of the adverse tax consequences and Atmos Mid-Tex’s
failure to ensure the transfer of certain information relevant to previous interim rate adjustments, the
Examiners recommended that the Commission find the merger not in the public’s best interest and
make adjustments to disallow the effect of the transaction. The Commission disagreed with the
Examiners’ recommendation and found that the merger was in the public interest and that no
adjustment to rate base to disallow the effect of the transaction was necessary. While the
Commission’s relevant finding of fact states that the merger between “Atmos Mid-Tex and TXU
Gas” was consistent with the public interest, it is apparent from the Proposal for Decision and
evidence presented by the parties in GUD Docket No. 9760 that the transaction being considered was
the merger between TXU Gas and Atmos Energy as a whole, not simply the portion of the
transaction involving the distribution assets. Thus, as the Commission and Atmos Pipeline assert
on appeal, the Commission had, prior to the rate-making proceeding at issue in this case, already
found the merger to be in the public interest.
Even if, as the City contends, the public-interest finding in GUD Docket No. 9760
is “irrelevant to the determination as to [Atmos Pipeline]” or does not itself constitute a finding that
34
the merger transaction as a whole was in the public interest, we find substantial evidence to support
such a finding in GUD Docket No. 10000. The only criterion the statute directs the Commission to
consider in making the public-interest determination is the “reasonable value of the property,
facilities, or securities to be acquired, disposed of, merged, or consolidated.” Id. § 102.051(b).
Significantly, the Commission can make its determination by considering this factor with or without
a public hearing. Id. The Commission had before it the required information by virtue of the
verified responses Atmos Energy submitted to the Staff in response to the Requests for Information
propounded in GUD Docket No. 9555. Moreover, in this proceeding, Atmos Pipeline’s president,
Richard Erskine, testified that in October 2004 TXU Gas merged into Atmos Energy, a merger that
included the transmission pipeline assets that came to be held by Atmos Pipeline. Erskine testified
that this transaction had been found to be in the public interest by the Commission in GUD Docket
No. 9670. Erskine further testified that Atmos Energy has invested significant capital in the Atmos
Pipeline system. Erskine testified that, under Atmos Energy’s ownership, Atmos Pipeline has
continued to provide safe and reliable service to its customers consistent with their contracts for
service. According to Erskine, the merger was in the public interest because it allowed for the
expansion and fortification of the Atmos Pipeline system, resulting in safe and reliable service to
new and existing customers. We note that none of the parties who intervened in this rate-making
proceeding submitted any testimony to the effect that the merger was not in the public interest.
When determining whether an agency’s actions are supported by substantial evidence,
courts are prohibited from substituting their judgment for the Commission’s “as to the weight of the
evidence on questions committed to agency discretion.” City of Abilene v. Public Util. Comm’n,
35
146 S.W.3d 742, 748 (Tex. App.—Austin 2004, no pet.) (citing Tex. Gov’t Code § 2001.174). In
making this determination, courts are not asked to verify whether “the agency reached the correct
conclusion, but whether some reasonable basis exists in the record for the agency’s action.” Id. We
conclude that the Commission’s finding that the merger between Atmos Energy and TXU Gas was
in the public interest was supported by substantial evidence, including both the information received
in response to the Staff’s Requests for Information in GUD Docket No. 9555 and the testimony
provided by Erskine in the proceeding at issue here. We overrule the City’s second issue.
CONCLUSION
Having overruled all appellate issues raised by the Municipalities, the City, the
Steering Committee, and the State Agencies, we affirm the trial court’s judgment.
_____________________________________________
J. Woodfin Jones, Chief Justice
Before Chief Justice Jones, Justices Pemberton and Field
Affirmed
Filed: January 17, 2014
36