State Agencies & Institutions of Higher Education v. Railroad Commission

421 S.W.3d 690, 2014 WL 229952, 2014 Tex. App. LEXIS 566

• Court: Court of Appeals of Texas
• Decided: January 17, 2014
• Docket: 03-13-00018-CV
• Status: Published

Opinion

OPINION

J. WOODFIN JONES, Chief Justice.

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 transporta tion 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 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 Reve nue actually generated in a particular year, Atmos 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 pri- or 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 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 eost-of-service basis, rather than applying revenue 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 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 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 competitive customers’ use was inter-ruptible 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-interrup-tible, 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 pro vided 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 $226,772,582. The Commission arrived at that number using the traditional cost-of-service method whereby the utility’s 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-serviee 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 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 $88,723,391 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 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 expedient for administrative purposes. Cities 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 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 “establishflng] 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 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, 572 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 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 order must be reversed if it exceeds Commission’s statutory authority); Cities 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.

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).

We also disagree with appellants’ contention that Rider Rev violates GURA by guaranteeing Atmos Pipeline a certain amount of profit while GURA only author izes 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 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 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 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 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.

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, 43 S.Ct. 675, 67 L.Ed. 1176 (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 ana lyst 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 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 Staffs 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 Staffs 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 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 devélop 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. He- vert 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.

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 Staffs 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 [At-mos 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 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, He-vert 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 com panies 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 commensurate with those of At-mos 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. 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, 64 S.Ct. 281, 88 L.Ed. 333 (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, 43 S.Ct. 675 (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, 64 S.Ct. 281 (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 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 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 ser vices 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:

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 Staffs 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 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 adjust ments, 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 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.” Cities of Abilene v. Public Util. Comm’n, 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 Staffs 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.

1 . "CGS” is short for City Gate Service.

2 . "px” 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.

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.

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).

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.

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.

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, 28 Baylor L.Rev. 1083 (1976)).

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.

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).