# Entergy Texas, Inc.// Office of Public Utility Counsel and Public Utility Commission of Texas v. Public Utility Commission of Texas and Texas Industrial Energy Consumers// Office of Public Utility Counsel and Entergy Texas, Inc. > Texas Court of Appeals, 3rd District (Austin) · March 31, 2015 URL: https://www.frixlaw.com/law-library/cases/4062185 ## Case - **Court:** Texas Court of Appeals, 3rd District (Austin) - **Decided:** March 31, 2015 - **Precedential status:** Published - **Opinion:** Opinion - **Cited by:** 0 later opinions in the Frix Law Library ## Citator (automated) - No negative treatment found by the automated citator. That is not the same as a confirmation that the case is good law; read the citing cases. - Full citator and citing cases: https://www.frixlaw.com/law-library/cases/4062185 ## Opinion text ACCEPTED 03-14-00735-CV 4703327 THIRD COURT OF APPEALS AUSTIN, TEXAS 3/31/2015 9:04:27 AM JEFFREY D. KYLE CLERK No. 03-14-00735-CV IN THE FILED IN 3rd COURT OF APPEALS THIRD COURT OF APPEALS AUSTIN, TEXAS AT AUSTIN, TEXAS 3/31/2015 9:04:27 AM JEFFREY D. KYLE Entergy Texas, Inc., et al., Clerk Appellants v. Public Utility Commission of Texas, et al., Appellees Appeal from the 353rd Judicial District Court, Travis County, Texas The Honorable John K. Dietz, Judge Presiding ________________________________________________________________ APPELLANT’S BRIEF OF ENTERGY TEXAS, INC. _________________________________________________________________ John F. Williams State Bar No. 21554100 jwilliams@dwmrlaw.com Marnie A. McCormick State Bar No. 00794264 mmccormick@dwmrlaw.com DUGGINS WREN MANN & ROMERO, LLP 600 Congress Ave., Ste. 1900 (78701) P. O. Box 1149 Austin, Texas 78767-1149 (512) 744-9300 (512) 744-9399 fax ATTORNEYS FOR APPELLANT ENTERGY TEXAS, INC. March 2015 ORAL ARGUMENT REQUESTED IDENTITY OF PARTIES AND COUNSEL The following is a list of all parties to the order appealed from and the names and addresses of all trial and appellate counsel: Parties: Attorneys: Entergy Texas, Inc. John F. Williams Plaintiff in District Court Marnie A. McCormick Duggins Wren Mann & Romero, LLP 600 Congress Ave., Ste. 1900 (78701) P. O. Box 1149 Austin, Texas 78767-1149 Counsel in District Court and on Appeal Public Utility Commission of Texas Elizabeth R. B. Sterling Defendant in District Court Assistant Attorney General Environmental Protection Division Office of the Attorney General P.O. Box 12548 Austin TX 78711-2548 Counsel in District Court and on Appeal Office of Public Utility Counsel Sara J. Ferris Plaintiff/Intervenor in District Court Office of Public Utility Counsel 1701 N. Congress Ave., Ste. 9-180 Austin TX 78711-2397 Counsel in District Court and on Appeal Cities of Bridge City, et al. Daniel J. Lawton Plaintiff/Intervenor in District Court Lawton Law Firm PC 12600 Hill Country Blvd., Ste. R275 Austin TX 78738 Counsel in District Court i State Agencies Susan M. Kelley (retired) Plaintiff/Intervenor in District Court Office of the Attorney General P. O. Box 12548 Austin TX 78711-2548 Counsel in District Court Texas Industrial Energy Consumers Meghan Griffiths Intervenor in District Court Andrews Kurth LLP 111 Congress Ave., Ste. 1700 Austin TX 78701 Counsel in District Court Rex VanMiddlesworth Benjamin Hallmark Thompson Knight LLP 98 San Jacinto Blvd., Ste. 1900 Austin, Texas 78701 Counsel in District Court ii TABLE OF CONTENTS IDENTITY OF PARTIES AND COUNSEL ............................................................ i TABLE OF CONTENTS ......................................................................................... iii INDEX OF AUTHORITIES.................................................................................... vi STATEMENT OF THE CASE ................................................................................ ix STATEMENT REGARDING ORAL ARGUMENT ............................................. ix ADMINISTRATIVE RECORD .............................................................................. ix ISSUES PRESENTED...............................................................................................x STATEMENT OF FACTS ........................................................................................1 I.  Regulatory Framework ....................................................................................1 II.  Procedural History ...........................................................................................4 SUMMARY OF THE ARGUMENT ........................................................................5 ARGUMENT AND AUTHORITIES ........................................................................7 I.  The Commission erred in disallowing over $11 million associated with ETI’s unrecovered Hurricane Rita reconstruction costs. ........................7 A.  Background ...........................................................................................7 B.  The Commission erred as a matter of law in concluding that PURA required the insurance proceeds to be trued-up in Docket No. 37744. ...........................................................................................13 C.  The Commission also erred in treating the issue as if it had in fact been resolved in Docket No. 37744. ............................................15 D.  The Commission’s order contravenes legislative intent. ....................18 II.  The Commission erred in refusing to include any of ETI’s adjustments to test-year purchased capacity costs in setting rates. ...................................19 A.  Background .........................................................................................19 iii B.  The Commission misapplied the standard for adjustments to test-year expenses. ...............................................................................24 1.  Adjustments to test-year data are not extraordinary relief........24 2.  Adjustments to test-year data need not be proven with absolute certainty. .....................................................................26 C.  The Commission’s wholesale disallowance of any adjustment to test-year levels of capacity costs is not supported by substantial evidence.............................................................................27 1.  ETI proved that it will incur an annual capacity cost increase of $15.8 million under the Frontier contract...............28 2.  ETI proved that it will incur an annual capacity cost increase of $8.1 million under the SRMPA contract. ...............30 3.  ETI proved that it will incur an annual capacity cost increase of $14.1 million under the Calpine contract. ..............31 4.  The record does not reasonably support the Commission’s other reasons for disallowing 100 percent of these known capacity costs. ..................................................32 a.  Load Growth ...................................................................32 b.  MSS-1 Costs ...................................................................34 c.  MSS-4 Costs ...................................................................36 D.  The consequences of the Commission’s decision are extreme and unjust. ...........................................................................................38 III.  The Commission erred in setting ETI’s transmission equalization (MSS-2) expense at the test-year level. .........................................................39 A.  The Commission erred as a matter of law in applying the standard for adjustments to test-year expenses. ..................................41 B.  Additionally, the Commission’s adherence to test-year expense levels is unsupported by substantial evidence.....................................42 CONCLUSION AND PRAYER .............................................................................43 iv CERTIFICATE OF COMPLIANCE .......................................................................44 CERTIFICATE OF SERVICE ................................................................................45 APPENDICES .........................................................................................................47 v INDEX OF AUTHORITIES Cases B.L.M. v. J.H.M., III, No. 03-14-00050-CV, 2014 WL 3562559 *11 (Tex. App. – Austin Jul. 17, 2014, pet. denied) .................................................................................................17 Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of State of W.Va., 262 U.S. 679 (1923) ...............................................................................................2 Cameron v. Terrell & Garrett, Inc., 618 S.W.2d 535 (Tex. 1981) ................................................................................33 Cities of Dickinson v. Public Util. Comm’n of Tex., 284 S.W.3d 449 (Tex. App. – Austin 2009, no pet.) ...........................................11 City of Corpus Christi v. Public Util. Comm’n of Tex., 51 S.W.3d 231 (Tex. 2001) ..................................................................................10 City of El Paso v. Public Util. Comm’n of Tex., 344 S.W.3d 609 (Tex. App. – Austin 2011, no pet.) ................................ 3, 19, 20 City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179 (Tex. 1994) ............................................................... 3, 25, 26, 41 Commint Technical Services, Inc. v. Quickel, 314 S.W.3d 646 (Tex. App. – Houston [14th Dist.] 2010, no pet.) ......................16 Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex., 173 S.W.3d 199 (Tex. App. – Austin 2005, pet. denied) ......................................1 Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591 (1944) ...............................................................................................2 Idaho Power Co. v. Idaho State Tax Comm'n, 109 P.3d 170 (Idaho 2005) ...................................................................................10 Office of Consumer Counsel v. Department of Public Util. Control, 742 A.2d 1257 (Conn. 2000) ................................................................................10 Office of Consumer Counsel v. Department of Public Util. Control, 905 A.2d 1 (Conn. 2006) .....................................................................................10 Office of Public Util. Counsel v. Public Util. Comm’n of Tex., 104 S.W.3d 225 (Tex. App. – Austin 2003, no pet.) .............................................2 vi Starr County v. Starr Industrial Servs., Inc., 584 S.W.2d 352 (Tex. Civ. App. – Austin 1979, writ ref’d n.r.e.) ......................27 State of Texas' Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615 (Tex. App. -- Austin 2014, pet. requested) ........................ 10, 17 Suburban Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358 (Tex. 1983) ........................................................................... 3, 26 TXU Elec. Co. v. Public Util. Comm’n of Tex., 51 S.W. 3d 275 (Tex. 2001) (per curiam) ..............................................................8 Woods v. William M. Mercer, Inc., 769 S.W.2d 515 (Tex. 1988) ................................................................................16 Statutes Tex. Gov’t Code Ann. § 2001.174 .............................................................. 19, 39, 43 Tex. Gov’t Code Ann. § 2001.190...........................................................................17 Tex. Util. Code Ann. §§ 11.001, et seq. ....................................................................1 Tex. Util. Code Ann. §§ 36.001, et seq. ..................................................................14 Tex. Util. Code Ann. § 36.003 ...................................................................................2 Tex. Util. Code Ann. § 36.051 .................................................................. 2, 7, 25, 41 Tex. Util. Code Ann. §§ 39.001-.359 ........................................................................2 Tex. Util. Code Ann. § 39.452 ...............................................................................2, 8 Tex. Util. Code Ann. § 39.455 .................................................................................33 Tex. Util. Code Ann. § 39.458 ........................................................................ 7, 8, 18 Tex. Util. Code Ann. §§ 39.458-463 .................................................................. 7, 18 Tex. Util. Code Ann. § 39.459 ............................................................................ 7, 13 Tex. Util. Code Ann. § 39.462 ......................................................................... passim Rules 16 Tex. Admin. Code § 22.222 ................................................................................17 16 Tex. Admin. Code § 25.181 ..................................................................................4 16 Tex. Admin. Code § 25.231 ..................................................................... 3, 24, 41 16 Tex. Admin. Code § 25.234 ..................................................................................3 16 Tex. Admin. Code §§ 25.235-.237 .......................................................................4 vii 16 Tex. Admin. Code § 25.236 ......................................................................... 19, 20 16 Tex. Admin. Code § 25.238 ................................................................................20 Tex. R. Civ. P. 94 .....................................................................................................15 Commission Proceedings Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 ........................................................13 Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No. 32907 .................................................... passim Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 ............................................................17 viii STATEMENT OF THE CASE This is a suit for judicial review of the final order of the Public Utility Commission of Texas (the “Commission” or “PUCT”) in its Docket Number 39896, a proceeding initiated by Entergy Texas, Inc. (“ETI” or the “Company”) for authority to change its retail electric rates and reconcile fuel costs. ETI and several other parties to the contested case sought judicial review of the Commission’s order.1 The cases were consolidated.2 The district court, Judge John K. Dietz presiding, reversed the Commission’s order in one respect and summarily affirmed it in all other respects.3 STATEMENT REGARDING ORAL ARGUMENT Cases involving public utility regulation usually involve complex regulatory principles, and this one is no exception. For that reason, the Court’s decisional process would be aided by oral argument. ADMINISTRATIVE RECORD The Administrative Record (“AR”) comprises Joint Exhibits 4-13 of the Reporter’s Record. Joint Exhibit 13 was sealed per the requirements of Texas Rule of Civil Procedure 76a.4 Joint Exhibits 1-3 are indices to the record. 1 Clerk’s Record (“CR”) 5. The Clerk’s Record does not yet contain the petitions filed by parties other than ETI. 2 CR 81. 3 CR 2118. 4 CR 2109. ix ISSUES PRESENTED 1. The Commission disallowed over $11 million of costs that ETI incurred to restore its system after Hurricane Rita and that no one disputes ETI is entitled to recover. The Commission decided that ETI should have begun recovering these costs at the end of a previous rate case, Docket No. 37744, based upon a PURA provision and what the Commission characterizes as an ambiguity in the resolution of Docket No. 37744. a. Did the Commission erroneously interpret PURA as requiring resolution of this issue in Docket No. 37744, when PURA section 39.462(a) says ETI may recover these costs in “any” proceeding authorized by Chapter 36? b. Did the Commission err by requiring ETI to disprove its opponents’ res judicata theory that the order in Docket No. 37744 bars ETI from seeking recovery of the costs in this case? c. Does the record reasonably support the Commission’s decision that the order in Docket No. 37744 required ETI to begin recovering these costs, when everyone agrees the Commission’s order said nothing about the issue? 2. The Commission disallowed over $30 million of ETI’s expenses for purchasing capacity from third parties because the amount was not incurred in the test year and because the Commission found there was a possibility that some of the costs might be avoided or offset. a. Did the Commission err as a matter of law by treating adjustments to test-year levels of expense as “exceptional” and by refusing to make any adjustments for anticipated costs? b. Is every one of the Commission’s multiple theories about how the costs might be avoided or offset supported by substantial evidence? x 3. The Commission refused to make any adjustment to ETI’s test-year level of “transmission equalization” expense because the parties disagreed about how big an adjustment was warranted. a. Did the Commission err as a matter of law by requiring proof of adjustments to test-year expenses with absolute certainty? b. Is the Commission’s decision to set this expense at the test-year level supported by substantial evidence, when every witness who testified on this issue agreed the test-year level was too low? xi STATEMENT OF FACTS ETI is an investor-owned electric utility.5 ETI provides bundled generation, transmission, distribution, and customer services to over 400,000 retail customers, primarily in southeastern Texas.6 During the time periods at issue in this case, ETI served both wholesale and retail customers. I. Regulatory Framework ETI is a subsidiary of Entergy Corporation, which also owns other subsidiaries, or “operating companies,” including electric utilities in Louisiana, Arkansas, and Mississippi.7 The utility subsidiaries each own facilities separately, but they have historically coordinated and shared resources for providing and transmitting energy.8 This coordination across state lines is governed by the “Entergy System Agreement,” a tariff approved by the Federal Energy Regulatory Commission (“FERC”).9 ETI’s wholesale rates are also regulated by the FERC. See Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex., 173 S.W.3d 199, 207 (Tex. App. – Austin 2005, pet. denied). The services ETI provides to Texas retail customers are subject to regulation by the PUCT under the Public Utility Regulatory Act (“PURA”).10 The Texas 5 AR Binder 31, ETI Exh. 4 (Domino Direct at 1 of 38). 6 Id. 7 Id. 8 AR Binder 36, ETI Exh. 39 (Cicio Direct at 6-10 of 75). 9 Id. 10 See Tex. Util. Code Ann. §§ 11.001, et seq. 1 legislature in 1999 ordered electric utilities to “unbundle” their generation, transmission, distribution, and customer service functions as part of an effort to introduce competition into the Texas retail electric industry. See Tex. Util. Code Ann. §§ 39.001-.359. However, in 2009, the legislature amended PURA to require ETI to cease activities relating to the transition to retail competition. See id. § 39.452(i). Accordingly, ETI remains subject to traditional cost-of-service rate regulation. Id. § 39.452(a). Under traditional regulation, an electric utility provides service, from the acquisition to delivery of power, to all requesting customers in a service area at a Commission-approved “just and reasonable” rate. See Office of Public Util. Counsel v. Public Util. Comm’n of Tex., 104 S.W.3d 225, 227-28 (Tex. App. – Austin 2003, no pet.); see also Tex. Util. Code Ann. § 36.003(a). Under PURA and applicable constitutional principles, a utility is entitled to rates that afford it a “reasonable opportunity to earn a reasonable return on the utility’s invested capital used and useful in providing service to the public in excess of the utility’s reasonable and necessary operating expenses.” Tex. Util. Code Ann. § 36.051; Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944); Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of State of W.Va., 262 U.S. 679, 692 (1923). To set rates, the Commission determines each of these components, which cumulatively are the utility’s “revenue requirement” or 2 “cost of service.” See, e.g., City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179, 187 (Tex. 1994); 16 Tex. Admin. Code § 25.231. The PUCT by rule has adopted a process by which rates are based on a historical “test year,” adjusted for known and measurable changes. See 16 Tex. Admin. Code § 25.231(a). The Commission evaluates the reasonableness of the utility’s expenses, determines the appropriate level of capital investment (or rate base) and a reasonable rate of return on that investment, and then allocates the total revenue requirement among the utility’s various classes of customer. Id. §§ 25.231(b), (c) & .234. The central goal of this process is to arrive at cost recovery as representative as reasonably possible of the utility’s “cost situation expected in the future.” Suburban Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358, 366 (Tex. 1983). The utility generally bears the risk that its actual operating expenses will exceed the expectations incorporated into the rate, while retail customers bear the converse risk, during the regulatory “lag” between rate cases. City of El Paso v. Public Util. Comm’n of Tex., 344 S.W.3d 609, 613 (Tex. App. – Austin 2011, no pet.). Exceptions to this general rule of risk exist for certain categories of costs, such as fuel costs and energy efficiency costs. For these types of costs, the utility has a separate rate or “rider” through which it collects its projected costs. The 3 utility later must reconcile those revenues to its actual, reasonable costs so that it recovers no more or less than its actual, reasonable costs for the particular category of expense covered by the rider. See, e.g., 16 Tex. Admin. Code §§ 25.235-.237 & § 25.181. II. Procedural History The Company initiated the underlying general rate case because the rates in effect did not adequately compensate it for its cost of providing service.11 Among other things, ETI’s third-party purchased power costs were doubling, a study showed that its current depreciation rates were severely understated, and its actual return on equity was some three percentage points lower than its then-authorized return.12 ETI sought a total annual increase of $104.8 million.13 The “test year” for the Company’s application was July 1, 2010 through June 30, 2011.14 Rates were proposed to go into effect in June 2012.15 After an evidentiary hearing, four Administrative Law Judges (“ALJs”) issued a proposal for decision recommending that ETI’s rates be increased by a total of $28.3 million annually.16 The Commission, with a few exceptions, adopted 11 AR Binder 31, ETI Exh. 4 (Domino Direct at 7 of 38). 12 Id. at 7-8. 13 AR Binder 37, ETI Exh. 55 (LeBlanc Rebuttal at 7 of 14). 14 AR Binder 31, ETI Exh. 4 (Domino Direct at 8 of 38). 15 AR Binder 43, Vol. K (5/2/12 Tr. at 1540). 16 See AR Binder 7, Item 244 (Order on Rehearing at 1). 4 the proposal for decision and ordered that ETI’s rates be increased by a total of $27.7 million annually. ETI appealed several aspects of the final order to the district court.17 Several parties that intervened in the Commission proceeding, including a group of cities (“Cities”), the Office of Public Utility Counsel (“OPUC”), and State Agencies, also appealed.18 The district court sustained one of ETI’s points, reversing the Commission’s decision on that issue.19 The court summarily affirmed the Commission’s order in other respects.20 More detailed facts are explained below in the context of the specific errors ETI brings to this Court. SUMMARY OF THE ARGUMENT This case is about several multi-million-dollar outlays that ETI made to serve its customers, but that the Commission refused to include in ETI’s rates. First, ETI spent millions of dollars reconstructing its system after Hurricane Rita. The Commission long ago determined these costs were reasonable and necessary, and that ETI was entitled to recover them. Nevertheless, the Commission has now disallowed over $11 million of these costs on the theory that ETI should have started recovering them after its 2009 rate case. This decision is 17 CR 5. 18 Though the separate appeals were consolidated, CR 81, the Clerk’s Record does not yet contain the petitions filed by parties other than ETI. In any event, after the cases were consolidated, State Agencies nonsuited their appeal but remained in the case as an intervenor defendant. CR 2084 & 2085. 19 CR 2118. 20 Id. 5 based upon an erroneous interpretation of a PURA provision. It is also based upon a legally and factually unsupportable conclusion that ETI should have divined that it was required to begin recovering these costs after the 2009 rate case, even though the order in that case said no such thing. Second, ETI spent millions of dollars purchasing third-party capacity to serve its customers. Even though the Commission did not find that these purchases were unreasonable or unnecessary, the Commission refused to include the costs in ETI’s rates. The Commission’s decision is based upon an erroneous insistence that test-year data is more important than evidence of what costs the Company expects to bear when the rates go into effect. It is also based upon several fact-findings that ETI might be able to avoid or offset some of these costs. These findings do not support a total disallowance of the purchased capacity costs and are not rationally based upon the record evidence. Similarly, ETI spent millions of dollars to pay for its share of the multi- jurisdictional transmission network that supports service to its customers, and those costs dramatically increased after the test year. Even though every witness who testified about this issue agreed that the test-year level of this expense was too low, the Commission refused to make any adjustment because the witnesses did not agree on how much of an increase was warranted. This decision is another example of the Commission’s erroneous application of the standard for calculating 6 expenses that should be included in rates. It is also unsupported by substantial evidence. The effect of all these decisions was that ETI had to bear all these costs at shareholder expense until its next rate case. ETI, therefore, did not have the opportunity to earn the reasonable return on its investment to which it is entitled under PURA. See Tex. Util. Code Ann. § 36.051. Because these decisions were fraught with error, this Court should reverse them. ARGUMENT AND AUTHORITIES I. The Commission erred in disallowing over $11 million associated with ETI’s unrecovered Hurricane Rita reconstruction costs. A. Background In 2005, Hurricane Rita struck the upper Texas coast, causing extensive damage to southeastern Texas. The next year, the legislature enacted a set of provisions in PURA that entitles electric utilities like ETI to timely recover reconstruction costs they reasonably and necessarily incurred as a result of the hurricane. See Tex. Util. Code Ann. §§ 39.458-463. The enactment requires the Commission, upon application by a utility, to determine whether particular hurricane reconstruction costs were reasonably and necessarily incurred and thus eligible for recovery. Id. §§ 39.459(a)(1) & 39.462(b). This determination need not be made in the context of a base-rate proceeding under PURA Chapter 36. Id. § 39.462(e). 7 If, upon a utility’s application, the Commission determines it would benefit ratepayers for the utility to recover eligible costs through “securitization” financing,21 as opposed to “conventional financing methods,” the Commission must adopt a financing order authorizing the utility to issue bonds. Id. § 39.458. The bonds are repaid or secured by charges to ratepayers in the utility’s service area. E.g., TXU Elec. Co. v. Public Util. Comm’n of Tex., 51 S.W. 3d 275, 277 (Tex. 2001) (per curiam). Alternatively, a utility is entitled to recover eligible reconstruction costs in a base rate proceeding “or through any other proceeding authorized by Subchapter C, Chapter 36” of PURA. Tex. Util. Code Ann. § 39.462(a). In December 2006, ETI’s predecessor22 initiated a proceeding to determine whether certain of its Hurricane Rita reconstruction costs were eligible for recovery and securitization.23 The parties to that case reached a settlement and 21 Securitization is a specialized form of debt financing where repayment of bondholders achieves a high degree of assurance, resulting in very low bond interest rates. 22 ETI’s predecessor was Entergy Gulf States, Inc. (“EGSI”). EGSI provided retail electric service in both Texas and Louisiana. In 2005, the Texas Legislature enacted legislation providing that EGSI could proceed with and complete jurisdictional separation of its Texas and Louisiana operations to establish two separate, vertically integrated utilities. See Tex. Util. Code Ann. § 39.452(e). By January 1, 2008, EGSI had separated into ETI, a Texas-only utility, and Entergy Gulf States Louisiana, L.L.C., a Louisiana-only utility. 23 See Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No. 32907 (Jul. 5, 2006 Application). Public filings in Docket No. 32907 and other Commission dockets may be accessed at the Commission’s interchange: http://interchange.puc.texas.gov/WebApp/Interchange/application/dbapps/filings/pgSearch.asp by entering the docket number in the “Control Number” field. 8 agreed that $381,236,384 of the expenses at issue were eligible.24 Because ETI expected to receive insurance proceeds of $65,700,000 in the future, the settlement provided that ETI would deduct that amount from its eligible costs.25 The parties agreed that ETI should be allowed to securitize $381,236,384, plus carrying costs, minus the $65.7 million estimated insurance proceeds, plus other qualified costs.26 It was understood that the Company might not receive exactly $65,700,000 in insurance proceeds, so the parties further agreed that after ETI received all of its insurance payments, a true-up would occur to determine the difference between the $65,700,000 estimate and the amount actually received.27 The parties agreed that ETI would accrue interest on the anticipated payments until they were actually paid, either by insurance companies or ratepayers.28 The Commission approved the parties’ agreement.29 The order provided that if ETI received more insurance payments than estimated, the excess would be passed through to ratepayers via a rider.30 But the agreed rider was only for over- recovery. Neither the settlement nor the order specified a method for recovering any insurance under-recovery from ratepayers. 24 See Docket No. 32907 (Nov. 17, 2006, Settlement Agreement at 2 of 10). 25 Id. at 3 of 10. 26 Id. at 5 of 10. 27 Id. at 3 of 10. 28 Id. 29 See id. (Dec. 1, 2006, Order at 1). 30 Id. at FOF 30. 9 By 2009, ETI had received only $46,013,904 in insurance proceeds, resulting in a $19,686,096 under-recovery of its actual, eligible hurricane reconstruction costs.31 ETI carried this unrecovered balance on its books, with interest, as a regulatory asset32 because the Commission’s order in Docket No. 32907 expressly contemplated that ETI would be authorized to recover these amounts in the future.33 In 2009, ETI filed a base rate case, Docket No. 37744. By that time, ETI had recovered most of the insurance proceeds it expected to recover, and it sought permission to begin recovering the regulatory asset of $19,686,096, plus interest, on a five-year amortization schedule.34 31 AR Binder 5, Item 185 (Proposal for Decision at 16). 32 A “regulatory asset” is a mechanism by which a utility carries a cost on its books as a balance sheet asset based on the expectation that a regulator will allow the utility to recover the cost over a period of years in the future instead of at the time the expenditure is made. E.g. Office of Consumer Counsel v. Department of Public Util. Control, 905 A.2d 1, 7 (Conn. 2006); Idaho Power Co. v. Idaho State Tax Comm'n, 109 P.3d 170, 173 (Idaho 2005); Office of Consumer Counsel v. Department of Public Util. Control, 742 A.2d 1257, 1263 (Conn. 2000); City of Corpus Christi v. Public Util. Comm’n of Tex., 51 S.W.3d 231, 238 (Tex. 2001); State of Texas' Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615, 646 (Tex. App. -- Austin 2014, pet. requested). Public utility commissions often permit utilities to recover large capital expenditures on this deferred basis to avoid the “rate shock” that could result if the costs were passed on to ratepayers all at once. E.g., Office of Consumer Counsel, 905 A.2d at 7; Idaho Power Co., 109 P.3d at 173. A regulatory asset is, therefore, a future debt of the ratepayers. Office of Consumer Counsel, 905 A.2d at 7. Regulatory assets are recovered over time from ratepayers on an “amortized” schedule. See Idaho Power Co., 109 P.3d at 173; Office of Consumer Counsel, 742 A.2d at 1263. 33 Docket 32907 (Dec. 1, 2006, Order at FOF 28) (authorizing ETI to accrue carrying costs on estimated insurance proceeds until paid by insurance companies or until the trued-up amount “is recovered in base rates”); AR Binder 5, Item 185 (Proposal for Decision at 19). 34 AR Binder 5, Item 185 (Proposal for Decision at 16). Again, as explained above in footnote 32, regulatory assets are traditionally “amortized.” That means they are recovered over a period of time so they are not charged to ratepayers all at once. 10 Docket No. 37744 was concluded by a “black box” settlement that did not mention the Hurricane Rita regulatory asset.35 Neither the parties’ stipulation nor the PUCT’s order in Docket No. 37744 directed ETI to begin amortizing the regulatory asset or otherwise prescribed a method for recovering it. Neither indicated an intent to alter ETI’s rights under PURA section 39.462 and the Commission’s order in Docket No. 32907.36 ETI, therefore, continued to account for and accrue interest on the unrecovered regulatory asset. After Docket No. 37744, ETI received an additional $5.7 million in insurance proceeds.37 In its next rate case, the one underlying this appeal, ETI sought permission to begin recovering the updated balance of the reconstruction costs eligible for recovery. With interest, that balance totaled $26,229,627.38 The ALJs recommended ETI recover only $15,175,563.39 The ALJs determined that even though the order in Docket No. 37744 did not say so, ETI should have begun amortizing the regulatory asset on August 15, 2010, the effective date of the rates approved in that docket.40 The ALJs expressed two rationales for their decision. First, they concluded that PURA required any 35 In a “black box” settlement, the parties agree to a total amount that a utility can recover through its rates without specifying any of the individual numbers used to calculate the amount. See, e.g., Cities of Dickinson, et al. v. Public Util. Comm’n of Tex., 284 S.W.3d 449, 450 (Tex. App. – Austin 2009, no pet.). 36 Docket No. 32907, supra (Nov. 17, 2006, Settlement Agreement; Dec. 1, 2006, Order). 37 AR Binder 37, ETI Exh. 46 (Considine Rebuttal at 18). 38 Id.; AR Binder 5, Item 185 (Proposal for Decision at 16). 39 AR Binder 5, Item 185 (Proposal for Decision at 23). 40 Id. at 21-22. 11 true-up of insurance proceeds to occur in the first base rate case after the reconstruction costs were deemed eligible for recovery.41 The ALJs believed that Docket No. 37744 was that case.42 Second, though they characterized the issue as a “close call,”43 the ALJs concluded that the amortization of the unrecovered costs “should be considered as having been approved in Docket No. 37744.”44 They believed the proposed amortization was not disputed in Docket No. 37744, and that ETI therefore had the burden of proving the issue was not resolved in the docket.45 Because they believed ETI did not meet that burden, they treated the issue as if it had already been resolved.46 The ALJs determined that if ETI had begun amortizing the regulatory asset upon the conclusion of Docket No. 37744, only $15,175,563 would be left to deal with in this case.47 The Commission adopted the ALJs’ recommendation.48 This decision must be reversed, because all the rationales for it are flawed. 41 Id. at 15 & 21-22. 42 Id. at 16 & 22. 43 Id. at 20. 44 Id. at 22. 45 Id. 46 Id. 47 Id. at 23. 48 AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 19-22). 12 B. The Commission erred as a matter of law in concluding that PURA required the insurance proceeds to be trued-up in Docket No. 37744. The ALJs relied upon PURA section 39.459(c) in concluding that the insurance proceeds were required to be trued up in the first base rate case after the reconstruction costs were deemed eligible for recovery.49 Section 39.459(c) reads: To the extent a utility subject to this subchapter receives insurance proceeds, governmental grants, or any other source of funding that compensates it for hurricane reconstruction costs, those amounts shall be used to reduce the utility’s hurricane reconstruction costs recoverable from customers. If the timing of a utility’s receipt of those amounts prevents their inclusion as a reduction to the hurricane reconstruction costs that are securitized, the commission shall take those amounts into account in: (1) the utility’s next base rate proceeding; or (2) any proceeding in which the commission considers hurricane reconstruction costs. Tex. Util. Code Ann. § 39.459 (c) (emphasis added). The Commission, in adopting the ALJs’ construction of this provision, erred as a matter of law.50 PURA section 39.459(c) requires the Commission to remedy a double- recovery if a utility receives insurance or grant money for hurricane reconstruction costs after those same costs have already been securitized. That is the exact 49 AR Binder 5, Item 185 (Proposal for Decision at 15 & 21-22). 50 The Commission also erred as a matter of fact in assuming that Docket No. 37744 was ETI’s first base rate case after the reconstruction costs were deemed eligible for recovery in Docket No. 32907. There was another base rate case filed and decided between Docket Nos. 32907 and 37744. See Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800. 13 opposite of what happened here. In Docket No. 32907, ETI agreed not to securitize amounts it expected to recover from insurance. Therefore, in the language of the statute, the timing of ETI’s receipt of those amounts did not prevent their inclusion as a reduction to the amounts that were securitized. The Attorney General conceded in the district court that the wording of section 39.459(c) “is not an exact match to the circumstances of this case.”51 Indeed, section 39.459(c) is by its plain terms inapplicable. Section 39.462(a), on the other hand, speaks directly to this situation. It says: An electric utility subject to this subchapter is entitled to recover hurricane reconstruction costs consistent with the provisions of this subchapter and is entitled to seek recovery of amounts not recovered under this subchapter … in its next base rate proceeding or through any other proceeding authorized by Subchapter C, Chapter 36. Id. § 39.462(a) (emphasis added). There is no question that the proceeding underlying this appeal was authorized by PURA Subchapter C, Chapter 36. See id. § 36.001, et seq. Therefore, the Commission was expressly authorized to address the issue in this case. It certainly was not statutorily required to address the issue in Docket No. 37744 or some other particular case. 51 CR 698 (PUCT Initial Brief at 14). 14 C. The Commission also erred in treating the issue as if it had in fact been resolved in Docket No. 37744. Nothing in the settlement agreement or final order in Docket No. 37744 even mentioned the regulatory asset, much less a method of recovering it. The ALJs acknowledged that.52 They also recognized that utilities are typically not allowed to recover regulatory assets without express approval of the Commission.53 The ALJs nevertheless concluded that the proposed amortization of the regulatory asset should be “considered to have been approved” in Docket No. 37744. They believed that the proposed amortization was not disputed in Docket No. 37744 and that ETI consequently should be required to prove the issue was not resolved in Docket No. 37744.54 Both of these assumptions are incorrect. First, as a matter of law, ETI did not bear the burden of proving what issues Docket No. 37744 did or did not resolve. The issue of whether Docket No. 37744 bars ETI from seeking particular relief in a subsequent case was a defensive issue raised by intervenors.55 The argument is really that the order in Docket No. 37744 is res judicata of the reconstruction cost recovery issue. Because that is an affirmative defense, intervenors bore the burden of proof on the issue. See, e.g., Tex. R. Civ. P. 94; Woods v. William M. Mercer, Inc., 769 S.W.2d 515, 517 (Tex. 52 AR Binder 5, Item 185 (Proposal for Decision at 20-21). 53 Id. at 21. 54 Id. at 22. 55 See, e.g., AR Binder 8 (Cities Exh. 2, Garrett Direct at 11). 15 1988); Commint Technical Services, Inc. v. Quickel, 314 S.W.3d 646, 651 (Tex. App. – Houston [14th Dist.] 2010, no pet.). There is no reasonable basis in the record upon which to conclude that the parties or the Commission intended ETI to begin amortizing the regulatory asset years ago. The only reason the intervenors gave in support of their argument was their allegation that the issue was “undisputed” in Docket No. 37744. It is true that no party to Docket No. 37744 argued that ETI should not recover the money at all.56 They could not, given that Docket No. 32907 and PURA clearly entitle ETI to recover the full amount of its eligible restoration costs. Regardless, the parties’ litigation positions during the contested phase of a proceeding do not inform what the parties intend when they settle the case, or what the Commission intends in approving the settlement. Even assuming for the sake of argument that the parties’ litigation positions in Docket No. 37744 were relevant, their positions on whether ETI was entitled to recover the money at all would not be the relevant issue. What would matter is what the parties’ positions were on how and when ETI should recover the money, because that is the issue the Commission says was resolved in Docket No. 37744. Cities’ witness in Docket No. 37744, Jacob Pous, did dispute ETI’s request to amortize the regulatory asset over a five-year period. He testified that ETI should 56 See id. at 11. 16 credit the amount to its storm reserve instead.57 The ALJs were mistaken in concluding that this issue was uncontested in Docket No. 37744.58 There certainly is no evidence in this docket that the parties or the Commission intended ETI to begin amortizing the regulatory asset upon the conclusion of Docket No. 37744. Given that neither the settlement agreement nor the Commission’s order said anything about this issue, and especially since the issue was disputed, ETI would have been unreasonable to “assume” it could begin amortizing the regulatory asset when Docket No. 37744 was over. As this Court recently recognized, the recovery of a regulatory asset is a two-step process. First, the Commission allows creation of the asset, and later, the Commission decides how the utility may recover the asset in rates. State of Texas' Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615, 646 (Tex. App. -- Austin 2014, pet requested). Here, the settlement and Commission order in Docket No. 32907 established that the hurricane reconstruction costs were reasonable and necessary and authorized creation of the regulatory asset. But the Company’s proposed 57 See Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 (Pous Direct at 113). Both the Commission and this Court may take notice of the fact this testimony was filed in Docket No. 37744. Tex. Gov’t Code Ann. § 2001.190; 16 Tex. Admin. Code § 22.222(a); B.L.M. v. J.H.M., III, No. 03-14-00050-CV, 2014 WL 3562559 *11 (Tex. App. – Austin Jul. 17, 2014, pet. denied) (not designated for publication). 58 In contrast, the ALJs correctly observed that another issue – regarding ETI’s storm reserve balance -- was disputed in Docket No. 37744. AR Binder 5, Item 185 (Proposal for Decision at 48). They concluded that issue was not resolved by the black box settlement. Id. Using the ALJs’ own logic, this fact leads to the conclusion that the Hurricane Rita issue was not adjudicated in Docket No. 37744. Resolving two issues differently based on materially similar facts is the essence of arbitrary and capricious action. 17 method of recovering that asset in Docket No. 37744 was a contested issue, and neither the parties’ settlement nor the Commission’s order resolved the issue in favor of one party or another. The only reasonable thing for the Company to do was to maintain the status quo, carrying the balance on its books as a regulatory asset until the Commission affirmatively addresses how the Company may recover it.59 D. The Commission’s order contravenes legislative intent. The Commission’s decision thwarts the legislature’s purpose in enacting the hurricane reconstruction cost recovery provisions. See Tex. Util. Code Ann. §§ 39.458-.463. The legislature clearly intended to ensure that utilities that incurred reconstruction costs as a result of Hurricane Rita would be able to expeditiously recover those costs in full, with interest. Indeed, the legislature expressly articulated this purpose in PURA. Id. § 39.458. The effect of the Commission’s order here is to disallow over $11 million in unrecovered hurricane reconstruction costs and interest. The order penalizes the utility for, instead of securitizing all of its hurricane reconstruction costs as authorized by the statute, opting not to securitize amounts that it anticipated recovering through insurance. No one has suggested that ETI was unreasonable in estimating its anticipated 59 Even Cities opined that the Docket No. 37744 settlement should not be interpreted as changing the status quo unless expressly stated in the settlement agreement or the final order. See AR Binder 5, Item 185 (Proposal for Decision at 17). 18 insurance proceeds when the securitization docket was taking place. The Commission’s reasons for disallowing the amounts that were not ultimately recovered through insurance are not legally or factually sound. The Court should reverse the Commission’s disallowance. See Tex. Gov’t Code Ann. § 2001.174(b)(2). II. The Commission erred in refusing to include any of ETI’s adjustments to test-year purchased capacity costs in setting rates. A. Background “Capacity” is the amount of power a utility has available at any given time to serve customers. Utilities are required to have a percentage surplus or “cushion” of capacity available in reserve, in case demand exceeds expectations. Traditionally regulated utilities supply their need for capacity either by owning generating plants or by buying capacity from someone else. A utility’s capital investment in building and maintaining its own plant become a part of its invested capital (or “rate base”), and the utility earns a return on that investment. The cost of fueling a power plant and other specified variable “energy” charges incurred to generate power are recoverable dollar-for-dollar as fuel expenses. 16 Tex. Admin. Code § 25.236(a); City of El Paso, 344 S.W.3d at 614. Purchases of capacity from third parties are, however, treated differently. They are simply expenses, and earn no return for the utility. Moreover, the fixed 19 costs associated with obtaining capacity from third parties may not, absent special circumstances, be recovered as fuel expenses. 16 Tex. Admin. Code § 25.236(a)(4); City of El Paso, 344 S.W.3d at 614. Instead, they are recovered through base rates. Id.60 Like other base rate expenses, “purchased capacity costs” are quantified during a “test year,” are adjusted for known and measurable changes, and become a component of the utility’s revenue requirement that forms the basis for prospective rates. There is no true-up or reconciliation for the purchased capacity costs recovered through base rates. Combined with the fact that there is no opportunity to earn a return on this type of expense, the adverse financial impact of “regulatory lag” is much more significant for this type of expense than it is for reconcilable fuel costs. Before 2009, ETI was under a regulatory directive to position itself for retail competition, and that directive necessitated that the Company forego long-term resource procurement. During that time, ETI relied on or “shared” the capacity from Entergy System resources owned by other Entergy operating companies, and relied on short- and limited-term resources to reliably serve its retail customers.61 ETI paid for this Entergy System capacity under Schedule MSS-1 of the Entergy System Agreement. That FERC-approved tariff requires the various Entergy 60 In some circumstances, Commission rules allow utilities to recover purchased capacity costs through a rider. See 16 Tex. Admin. Code § 25.238. ETI does not have such a rider. 61 See AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5-6 of 21); AR Binder 43, Vol. L (5/3/12 Tr. at 1939). 20 operating companies to make and receive payments according to their relative share of total system capacity.62 Some Entergy operating companies own a greater share of Entergy System capacity than they need to serve their own load.63 These entities are considered “long” on capacity.64 Other companies own less than they need, and are “short” on capacity.65 Under Schedule MSS-1, “short” companies pay “long” companies a per-MW rate for the cost of owning these capacity reserves.66 While it was in regulatory limbo, ETI controlled relatively less resources compared to its load than other Entergy companies. It, therefore, made “reserve equalization” payments under Schedule MSS-1.67 In addition to sharing Entergy System capacity under Schedule MSS-1, ETI also purchased power from specific units owned by other Entergy operating companies. Those unit-specific purchases were paid for under contracts with those operating companies under Schedule MSS-4 of the Entergy System Agreement. Schedule MSS-4 contains a formula that sets the price of power for these purchases based on the actual cost of producing the power.68 After the legislature in 2009 delayed the onset of retail competition in ETI’s service area, ETI found it cost effective to begin to substantially increase its 62 AR Binder 36, ETI Exh. 39 (Cicio Direct at 11-12 of 75). 63 Id. at 12. 64 Id. 65 Id. 66 Id. at 13-14. 67 AR Binder 35, ETI Exh. 34 (Cooper Direct at 22-23 of 25). 68 AR Binder 36, ETI Exh. 39 (Cicio Direct at 24-26 of 75). 21 reliance upon purchases of capacity from third parties.69 ETI did not buy more third-party capacity simply to serve additional load. Rather, ETI employed the strategy to serve existing load, reduce its reliance on Entergy capacity resources, and render ETI less “short” compared to other Entergy entities.70 The strategy also reduced fuel costs for customers because the third-party resources were by and large more fuel-efficient than the combined Entergy resources and, as explained above, there was no return component included in the cost.71 In this case, ETI asked the Commission to recognize the cost of ETI’s increased reliance on three new third-party purchased capacity contracts. Those contracts cost ETI some $38 million annually. ETI recognized that these contracts would enable ETI annually to avoid about $8 million of the costs it paid to Entergy affiliates for their capacity in the test year. ETI, therefore, asked the Commission to increase its test-year expenses for purchased capacity by the net amount of about $30 million for purposes of setting its annual rates. No party challenged the wisdom of ETI’s entering into any of the new, third- party contracts or the prices reflected in the contracts. The ALJs, however, included in ETI’s base rates only purchased capacity costs that were incurred 69 E.g, AR Binder 35, ETI Exh. 34 (Cooper Direct at 23 of 25). 70 AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5 of 21); see also id. at 10-11; AR Binder 37, ETI Exh. 57 (May Rebuttal at 13-15 of 31). 71 AR Binder 35, ETI Exh. 34 (Cooper Direct at 24 of 25); AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 7-8 of 21). 22 during ETI’s test year.72 The ALJs disallowed 100 percent of the additional expense associated with the third-party capacity contracts that would be incurred during the first year rates would be in effect (the “rate year”) and thereafter.73 The Commission adopted the ALJs’ proposal for decision on this issue.74 The ALJs concluded that ETI had not proven that the costs it would incur as a result of entering into the third-party purchase capacity contracts were “known and measurable” adjustments to the utility’s test-year expenses.75 The ALJs found that there is “substantial uncertainty” about what ETI will be obligated to pay for the third-party purchased capacity because the third parties might not fully perform their obligations under the contracts.76 The ALJs suggested that the contract costs should not be in rates because they may be offset by increased revenues from load growth.77 The ALJs further found there is “substantial uncertainty” about how much money the third-party purchased power capacity contracts will enable ETI to avoid paying to other Entergy entities under Schedule MSS-1 of the Entergy System Agreement.78 The source of this perceived uncertainty was apparently the ALJs’ view that the net costs were difficult to quantify because the calculations 72 AR Binder 5, Item 185 (Proposal for Decision at FOF 86). 73 Id. at FOF 73 & 86. 74 AR Binder 7, Item 244 (Order on Rehearing at 1 & 7). 75 AR Binder 5, Item 185 (Proposal for Decision at 108). 76 Id. at FOFs 77-78. 77 Id. at 109 & FOFs 84. 78 Id. at FOFs 75, 76, & 79-82. 23 involve projections and “complex” formulae and “variables.”79 Rather than accepting any of the calculations in evidence or adopting a result within the range of these recommendations, the ALJs simply disallowed the entire adjustment.80 The Commission’s order adopting these recommendations constitutes error of law and is not supported by substantial evidence. B. The Commission misapplied the standard for adjustments to test-year expenses. The fundamental error in the Commission’s order is that it misapplies the legal standard for determining what expenses should be included in rates. The order adopts the ALJs’ erroneous view that an adjustment to test-year data is somehow extraordinary or “exceptional” rate relief.81 The ALJs also took the view that to the extent additional costs are based on anticipated changes, they cannot be “known and measurable.”82 These assumptions are wrong as a matter of law. 1. Adjustments to test-year data are not extraordinary relief. To determine what a utility’s reasonable and necessary expenses are, the Commission determines “the electric utility’s historical test year expenses as adjusted for known and measurable changes.” 16 Tex. Admin. Code § 25.231(b). Under the rule, known and measurable changes have equal weight with historical 79 Id. at 108. 80 Id. at 109. 81 Id. at 108; AR Binder 7, Item 244 (Order on Rehearing at 1). 82 AR Binder 5, Item 185 (Proposal for Decision at 102). 24 test-year levels. That makes sense, because PURA does not limit a utility’s recoverable expenses to those incurred in a historical test year. Rather, PURA guarantees a utility a reasonable opportunity to earn a reasonable return on its investment over and above its “reasonable and necessary expenses.” Tex. Util. Code Ann. § 36.051. The goal of ratemaking is to set utility rates that will meet the utility’s and customers’ needs in the future, not the past, as rates are set on a prospective basis. The Texas Supreme Court has confirmed that making known and measurable adjustments is a critical component of establishing the costs upon which rates are set, and not a rare exception to the use of test-year cost levels. The Court has explained that “changes occurring after the test period, if known, may be taken into consideration by the regulatory agency to help mitigate the effects of inflation and in order to make the test year data as representative as possible of the cost situation that is apt to prevail in the future.” City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179, 188 (Tex. 1994) (emphasis added). The recognition of changes to test-year data is especially critical in a case such as this one, where the inability to recover substantial post-test-year expenses inevitably causes ETI to recover an inadequate return, contrary to the requirements of PURA’s fundamental cost-recovery standards. See Tex. Util. Code Ann. § 36.051. The Commission’s conclusion that a utility is somehow less entitled to 25 expenses that occur beyond the test year is contrary to PURA and judicial precedent, and its erroneous application of the known and measurable standard tainted the entirety of its decision on this issue. This is reason enough to reverse the Commission’s decision. 2. Adjustments to test-year data need not be proven with absolute certainty. The quantum of proof required to establish adjustments to test-year data is not greater than the quantum required to establish the test-year data itself. The Texas Supreme Court has held that known and measurable adjustments should be made if they reflect costs that will be “actually realized,” can be “anticipated with reasonable certainty,” and if they are representative of the costs “apt” to prevail in the future. See City of El Paso, 883 S.W.2d at 188; Suburban Util. Corp., 652 S.W.2d at 362. The standard is not an impossible-to-meet requirement of absolute or virtual certainty. Suburban Util. Corp., 652 S.W.2d at 362. Contrary to its ruling regarding purchased capacity, the Commission in this and other cases has routinely adopted known and measurable adjustments that involve estimates and uncertainty.83 In rejecting ETI’s proposed adjustments to test-year purchased capacity expense, the Commission did not acknowledge or discuss the statute, rule, judicial precedent, or regulatory precedent that guide its inquiry. The decision is 83 E.g., AR Binder 5, Item 185 (Proposal for Decision at 68 (short-term asset update), 163-64 (payroll adjustments), & 182-86 (ad valorem tax rate update)). 26 contrary to and inconsistent with all those authorities. Under the Commission’s analysis, known and measurable changes routinely adopted by the Commission would never be allowed. The Commission’s ruling is, therefore, arbitrary and capricious. See Starr County v. Starr Industrial Servs., Inc., 584 S.W.2d 352, 355- 56 (Tex. Civ. App. – Austin 1979, writ ref’d n.r.e.). This is another reason the decision must be reversed. C. The Commission’s wholesale disallowance of any adjustment to test-year levels of capacity costs is not supported by substantial evidence. The proposed adjustments for third-party purchased capacity expenses are attributable to three contracts the parties call the Frontier, Calpine, and Sam Rayburn Municipal Power Agency (“SRMPA”) contracts. ETI established with reasonable certainty what costs it would incur under each of these contracts while the rates being set in this case would be in effect. The Commission did not discuss the contracts separately, but ruled on them in the aggregate. The Commission said: 77. ETI’s projection of its rate-year third-party capacity contract payments includes numerous assumptions, one of which is that every single third-party supplier will perform at the maximum level under the contract, even though that assumption is inconsistent with ETI’s historical experience. 78. There is substantial uncertainty with regard to ETI’s projection of its rate-year third-party capacity contract payments.84 84 AR Binder 7, Item 244 (Order on Rehearing at FOFs 77-78); see also AR Binder 5, Item 185 (Proposal for Decision at 108-109). 27 These findings are not supported by substantial evidence. As discussed below, the adjustments were based on contracts already in place before and during the rate year. The contracts had clearly and specifically ascertainable prices and quantities, which were in evidence. No one disputed that ETI will pay money under these contracts. Rather, some parties speculated that ETI might not have to pay the full amount of these contracts because suppliers might not perform perfectly. Performance under each of the contracts is reasonably assured. There is no reasonable uncertainty regarding the outcome under any of these contracts, certainly none sufficient to support a finding that none of these contract costs are “apt to prevail” in the near future. 1. ETI proved that it will incur an annual capacity cost increase of $15.8 million under the Frontier contract. There is no reasonable basis in the evidence for the Commission’s finding that the costs of the Frontier contract are uncertain. ETI has had a contract with Frontier for years, leading up to and including the first ten months of the test year.85 In the second-to-last month of the test year, ETI increased the annual amount of power it purchased under the Frontier contract from 150 MW to 300 MW.86 Applying the language of the Texas Supreme Court, the 150 MW increase in capacity and capacity cost was “actually realized” in the test year. But because 85 AR Binder 43, Vol. L (5/3/12 Tr. at 1938 & 1941). 86 Id. at 1942 & 1959. 28 the step-up happened late in the test year, the test year does not reflect the full amount of expense ETI will incur going forward under the Frontier contract.87 No witness challenged ETI’s quantification of what this contract would cost ETI during the rate year. On cross-examination at the hearing, ETI’s witness Cooper acknowledged that ETI’s purchased capacity contracts include provisions that authorize ETI to reduce its payments if the counter-party does not perform.88 He explained that ETI did not assume any reduction in future payments for poor performance because in the past, any such adjustments have been “relatively minor.”89 ETI’s witness May, who quantified the increase in annual Frontier costs at $15.8 million, confirmed that ETI has “quite a bit of experiences” with the contract, and a “good understanding of what the costs are today and what the costs will be in the future” under the contract.90 The other parties did not produce evidence to the contrary. It is simply not reasonable to conclude, based upon this record, that there is “substantial uncertainty” about what ETI’s annual expenses will be in connection with the Frontier increase. The Commission’s findings insofar as they implicate this contract are not supported by substantial evidence. 87 Id. at 1942. 88 AR Binder 43, Vol. F (4/26/12 Tr. at 705-06); see also id. at 682. 89 Id. at 705. 90 AR Binder 43, Vol. L (5/3/12 Tr. at 1942). 29 2. ETI proved that it will incur an annual capacity cost increase of $8.1 million under the SRMPA contract. During the test year, ETI executed a 25-year agreement with SRMPA for 225 MW of capacity.91 Power started flowing under the contract on December 1, 2011, just five months after the end of the test year, well before intervenors filed their testimony in March 2012, and well before the conclusion of the proceeding under review.92 All of the capacity contracted for was allocated to ETI.93 The price of this contract is a “very straightforward $3 per kW a month.”94 It is “very easy to calculate what those known and measurable costs are.”95 $3.00 x 225,000 kW = $675,000 per month. At $675,000 per month, the contract will cost $8.1 million annually. No witness challenged ETI’s quantification of the annual costs of the SRMPA contract. In addition, the SRMPA contract commits “System Capacity,” meaning multiple network resources and substitute resources are designated to supply the capacity. There is no evidence in the record that SRMPA’s entire portfolio of network resources is likely to be simultaneously unavailable. There is, therefore, no evidence in the record that there is “substantial uncertainty” about whether SRMPA will perform the contract, or what the annual 91 AR Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25). 92 See id. 93 Id. at 17 & 19 of 25. 94 AR Binder 43, Vol. L (5/3/12 Tr. at 1944). 95 Id. 30 costs of the contract will be. The Commission’s findings insofar as they implicate this contract are not supported by substantial evidence. 3. ETI proved that it will incur an annual capacity cost increase of $14.1 million under the Calpine contract. ETI purchased capacity from Calpine Energy Services under a one-year contract in effect from June 1, 2008 through May 31, 2009.96 In 2009, ETI entered into a ten-year purchased power agreement with Calpine to purchase 485 MW of capacity from its Carville Energy Center.97 Purchases under this contract were set to begin on June 1, 2012, the beginning of the rate year for this case.98 Fifty percent of the contract was allocated to ETI.99 The resource had been under contract with the Entergy system for some time, and the Entergy companies have significant experience with the pricing and costs under the contract. The most recent contract simply allocated the resource differently to reflect the fact that the “overhang of retail competition” had been lifted for ETI.100 Because of ETI’s experience with Calpine, the capacity costs are “well known.”101 The contract sets out specific capacity quantities and prices, and includes default and other terms to ensure performance. ETI’s historical experience with the Calpine resource establishes that any deviations from the 96 AR Binder 35, ETI Exh. 34 (Cooper Direct at 21-22 of 25). 97 Id. at 16. 98 Id. 99 Id. at 19 of 25. 100 See AR Binder 43, Vol. L (5/3/12 Tr. at 1938). 101 Id. at 1942. 31 negotiated contract payments will be “very, very small.”102 Both parties to the contract intend and are incentivized to perform such that they will get the full benefits of the capacity and price under the contract.103 ETI projected the annual cost of the Calpine contract will be $14.1 million.104 No witness challenged ETI’s quantification of the costs associated with the Calpine contract. There is no evidence in the record that there is “substantial uncertainty” about whether Calpine will perform the contract, or what the annual costs of the contract will be. The Commission’s findings insofar as they implicate this contract are not supported by substantial evidence. 4. The record does not reasonably support the Commission’s other reasons for disallowing 100 percent of these known capacity costs. a. Load Growth Intervenors and Commission staff championed multiple theories they alleged would offset ETI’s additional expense under these three contracts. One such theory` was that the cost increase is not known and measurable because it may be offset by load growth that occurs after the test year.105 If it were appropriate to consider future load growth in setting base rates, PURA or the Commission’s rules would say so. Indeed, there are other instances 102 Id. 103 Id. at 1942-43. 104 AR Binder 8 (Cities Exh. 4B [Highly Sensitive], Goins Direct Exh. DWG-2). 105 AR Binder 5, Item 185 (Proposal for Decision at 109); AR Binder 7, Item 244 (Order on Rehearing at FOF 84). 32 in which PURA does specify that the utility’s recovery of costs should be subject to an offsetting load growth adjustment. See, e.g., Tex. Util. Code Ann. § 39.455 (utility entitled to recover specified incremental capacity costs “adjusted for load growth”). For base rates, the legislature has left load growth out of the equation, so that it may serve as a source of revenue to address other future cost increases and avoid or defer additional rate increases. The legislature’s inclusion of “load growth” language for specific circumstances but not base rates is evidence the legislature did not intend it to apply generally. Cameron v. Terrell & Garrett, Inc., 618 S.W.2d 535, 540 (Tex. 1981). Even if load growth could properly be considered, however, it does not support a wholesale disallowance of the increased purchased capacity costs. First, the load growth that intervenors suggested would occur would not fully materialize for at least two years.106 It could not logically offset the third-party capacity cost increases ETI began to experience during or shortly after the test year. Second, Cities witness Goins is the only intervenor witness who attempted to quantify a load growth adjustment, and he quantified it at $15.8 million – a far cry from the $38 million in increased purchased capacity expense that ETI proved it would incur.107 Moreover, Mr. Goins’s proposal overstated retail load growth 106 AR Binder 43, Vol. J (5/1/12 Tr. at 1299-1300 [Confidential]). 107 AR Binder 8 (Cities Exhs. 4 & 4B [Highly Sensitive], Goins Direct at 9 & 16-19). 33 significantly and attempted to predict events beyond the rate year.108 It does not provide a reasonable basis for a known and measurable change at all, much less one that negates all $38 million of ETI’s third-party capacity contract costs.109 The large gap between Mr. Goins’s speculative adjustment and the known costs ETI sought illustrates how far the Commission has strayed from setting rates at a level that will enable ETI to recover the costs it reasonably expects to incur when the rates are in effect. In any event, the Commission’s reliance on the load growth theory to deny ETI any adjustment for its post-test-year increases in third- party purchased capacity costs is not supported by substantial evidence. b. MSS-1 Costs Another “offset” theory that the Commission adopted concerned the amount of money ETI might save under Schedule MSS-1 as a result of the new third-party purchased capacity contracts. The Commission found that the impact the contracts would have on ETI’s “reserve equalization” payments under Schedule MSS-1 was substantially uncertain, because the calculation of MSS-1 costs depends on “numerous assumptions.”110 The record does not support a wholesale disallowance of ETI’s third-party capacity cost increases on this ground. 108 Id. at 17-19. 109 AR Binder 37, ETI Exh. 57 (May Rebuttal at 9-11 of 31); AR Binder 43, Vol. I (5/1/12 Tr. at pp. 1296-1306, 1316-1324 [Confidential]). 110 AR Binder 5, Item 185 (Proposal for Decision at 108); AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 75-76). 34 Company witness Cooper testified that the MSS-1 cost adjustment is a straightforward calculation.111 While it is true that the MSS-1 amount is dependent on the relative load responsibility of ETI, that relative change in load responsibility was factored into the Company’s calculation.112 Evidence from other parties regarding the MSS-1 costs likewise does not provide substantial evidence justifying a wholesale disallowance of the third-party contract costs. Cities, in fact, adopted ETI’s calculation of MSS-1 impacts.113 And though TIEC argued on one hand that ETI’s MSS-1 expense would increase over test-year levels,114 the evidence, including TIEC’s, is undisputed that MSS-1 costs go down as ETI adds new capacity contracts.115 In fact, the MSS-1 costs decreased during the test year and reached test-year lows during the last two months (when the new Frontier contract was first put in place).116 TIEC’s recommendations regarding MSS-1 costs are contrary to reality and all the record evidence. They certainly do not provide a reasoned basis to reject all of ETI’s proposed increase in third-party purchased capacity costs. 111 AR Binder 43, Vol. L (5/3/12 Tr. at 1947). 112 See AR Binder 35, ETI Exh. 34 (Cooper Direct at 20 of 25 & ETI Exh. 34A RRC-1 [Highly Sensitive]). 113 AR Binder 9, Cities Exh. 6 (Nalepa Direct at 17). 114 AR Binder 41, TIEC Exh. 1 (Pollock Direct at 26). 115 AR Binder 41, TIEC Exh. 1D (Pollock Direct at 22, Table 1); AR Binder 9, Cities Exh. 6 (Nalepa Direct Attachment KJN-3 at 2 [Highly Sensitive]). 116 See AR Binder 9, Cities Exh. 6 (Nalepa Direct Attachment KJN-3 at 2 [Highly Sensitive]). 35 c. MSS-4 Costs The Commission also found that the impact the purchased capacity contracts would have on MSS-4 costs (costs of unit-specific purchases from other Entergy operating companies) was substantially uncertain because the calculation of MSS-4 costs depends on “complex mathematical formulae that utilize numerous variables.”117 However, as shown in the proposal for decision adopted by the Commission, the adjusted MSS-4 costs sought by the Company are lower than the test-year level of MSS-4 costs awarded by the Commission. As the Commission further acknowledged, “while the purchases pursuant to MSS-4 [from test year to rate year] remain fairly stable, the third-party purchases will substantially increase, with a somewhat corresponding decrease for purchases pursuant to MSS-1.”118 In other words, the Commission recognized that the known and measurable adjustment to the test-year amount was driven by third-party purchases, not MSS-4 purchases. The small difference between the test-year and rate-year levels associated with MSS-4 purchases, under the Commission’s own observations, is not material to determining the merits of ETI’s proposed purchased power cost adjustments. In short, alleged uncertainty regarding the rate-year level of MSS-4 117 AR Binder 7, Item 244 (Order on Rehearing at FOFs 79-82). 118 AR Binder 5, Item 185 (Proposal for Decision at 100); AR Binder 7, Item 244 (Order on Rehearing at 1, adopting Proposal for Decision). 36 expense is not a reasonable basis for the Commission to reject ETI’s additional third-party purchased power expense. Even assuming arguendo that the Commission’s rejection of the Company’s adjustment to MSS-4 expense is material to the resolution of this issue, the evidence regarding MSS-4 expense does not support rejection of the entire increase in third-party purchased capacity costs. Similar to ETI, Cities’ and TIEC’s adjustments for MSS-4 costs in all but one respect varied only marginally from the test year. They come nowhere near to offsetting the entire cost of the third-party contracts.119 Cities and TIEC proposed MSS-4 reductions that were materially larger than ETI’s120 only because one of ETI’s Arkansas affiliate contracts (the “WBL” contract) was set to terminate after the test year. Intervenors’ argument was based on the flawed assumption that ETI would take no action to replace the WBL contract. To the contrary, the evidence was undisputed that ETI was short of capacity and in fact extended the very contract in question.121 The dispute over how much ETI might save in MSS-4 costs does not rationally support a disallowance of the entire increase for the new purchased capacity contracts 119 AR Binder 41, TIEC Exh. 1 (Pollock Direct at Exh. JP-1) (Line 4 shows $1.4 million reduction to test year amount of affiliate contracts)); AR Binder 8, Cities Exh. 4B (Goins Errata 3 Exh. DWG-2 [Highly Sensitive]) (less than $3 million reduction to test-year costs for affiliate contracts excluding WBL). 120 $12.7 million and $11.1 million, respectively. 121 AR Binder 43, Vol. E (4/26/12 Tr. at 687-88 & 696); AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5 of 21); AR Binder 43, Vol. L (5/3/12 Tr. at 1946). 37 D. The consequences of the Commission’s decision are extreme and unjust. The three new third-party purchased power contracts that drive ETI’s requested adjustment to test-year capacity costs benefit customers tremendously. They increase the capacity of ETI resources by 618 MW (150 by the Frontier contract, 225 by the SRMPA contract, and 243 by the half of the Calpine contract allocated to ETI). They result in substantial fuel savings for customers because of their diverse fuel resources and efficient heat rates.122 Customers will benefit from those savings on a dollar-for-dollar basis in fuel reconciliations. While the third- party owners of the capacity resources profit from the capacity payments ETI must make, and the retail customers of ETI benefit from the superior heat rates and resulting fuel savings, the Commission’s order forces the middleman – ETI –to pay for the capacity with shareholder funds. The Commission’s draconian adherence to the test-year data and incorrect application of the standard for making adjustments to that data are reasons alone to reverse the decision, because they taint every one of the Commission’s findings discussed above. Even disregarding those errors, none of the Commission’s findings rationally justifies the disallowance of 100 percent of the cost increase resulting from the three new contracts. Because the Commission did not quantify 122 AR Binder 35, ETI Exh. 34 (Cooper Direct at 24 of 25); AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 7-8 of 21). 38 how much of a disallowance it made upon each individual theory, if this Court finds any of the findings are unsupported by substantial evidence, it must reverse the whole disallowance and remand to the Commission for further consideration. This Court may not decide fact issues the Commission did not. Tex. Gov’t Code Ann. § 2001.174(1). III. The Commission erred in setting ETI’s transmission equalization (MSS- 2) expense at the test-year level. The Commission also erred in refusing to make any adjustment for another known and measurable increase in ETI’s expenses after the test year. The Entergy system transmission grid is a large network, the various pieces of which are owned by individual Entergy operating companies. The network, however, is integrated and operated for the mutual benefit of all of the Entergy operating companies.123 In any given month, some of the operating companies may be “long” on the amount of transmission capacity they own. That is, they own a portion of the transmission capacity that is greater than their share of the overall load placed on the transmission system. Other operating companies may be “short” on capacity. The Entergy System Agreement includes a FERC-approved Schedule MSS-2 that equalizes the ownership costs of certain high-voltage transmission facilities among the operating companies. The long operating companies receive MSS-2 payments 123 AR Binder 36, ETI Exh. 39 (Cicio Direct at 15 of 75); AR Binder 43, Vol. C (4/25/12 Tr. at 450); AR Binder 43, Vol. F (4/27/12 Tr. at 793). 39 from the short operating companies for the use of their transmission facilities so that each pays its fair share of the total ownership costs of the shared system on a monthly basis.124 Over the course of the test year, ETI was short, so it paid a total of $1,753,797 in MSS-2 payments to various other operating companies.125 But ETI’s MSS-2 expenses increased at the end of the test year and continued to increase after the test year.126 ETI anticipated these costs would increase even more by the rate year because of transmission projects that were planned to go into service by the rate year.127 ETI calculated that its MSS-2 expenses would be $10.7 million annually by the rate year.128 ETI sought to include that level of its expense in its rates. The ALJs recommended that the Commission disallow any increase in MSS- 2 expense over the test-year level. They found that the increased expenses were not “known and measurable,” again because the MSS-2 calculation depends on variables and projections, and because not all the projects ETI included in its 124 AR Binder 36, ETI Exh. 39 (Cicio Direct at 15 of 75); AR Binder 43, Vol. F (4/27/12 Tr. at 731 & 735-36). 125 AR Binder 43, Vol. F (4/27/12 Tr. at 724 & 737); AR Binder 9, Cities Exh. 28. 126 AR Binder 9, Cities Exh. 29. 127 AR Binder 43, Vol. F (4/27/12 Tr. at 761); AR Binder 37, ETI Exh. 59 (McCulla Rebuttal at 2-3 of 12). 128 AR Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Binder 43, Vol. F (4/27/12 Tr. at 738 & 760). 40 calculation were in service during the test year.129 The Commission adopted the ALJs’ recommendation that only the test-year level of MSS-2 expense should be included in ETI’s rates.130 A. The Commission erred as a matter of law in applying the standard for adjustments to test-year expenses. The Commission’s decision is flawed as a matter of law for the same reason its decision about purchased capacity costs is flawed. That is, the goal of ratemaking is to give the utility a reasonable opportunity to earn a reasonable return on its investment over and above its reasonable and necessary expenses. Tex. Util. Code Ann. § 36.051. Commission Rule 25.231 mirrors this principle. 16 Tex. Admin. Code 25.231. This undertaking cannot lawfully turn on the manner in which the calculation is made, or on the number of inputs to the calculation. The Commission cannot arbitrarily rely upon test-year levels of expense to the extent they are proven not to represent the level of expense the utility is reasonably anticipated to bear in the rate year, or that is “apt to prevail in the future.” City of El Paso, 883 S.W.2d at 188. If a change is known and can reasonably be measured, the Commission must make it. None of the opposing parties’ witnesses refuted that the projects underlying ETI’s proposed MSS-2 adjustment were already approved and in process, or that 129 AR Binder 5, Item 185 (Proposal for Decision at 116 & FOFs 87-93). 130 AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 87-94). 41 they will be completed. No intervenor or Staff witness offered any testimony or evidence casting doubt on the reasonableness of the construction cost estimates. Their position was simply that if there is any possibility of uncertainty or variability in the elements of an adjustment to test-year data, it must be denied. The Commission erred as a matter of law in adopting that standard. B. Additionally, the Commission’s adherence to test-year expense levels is unsupported by substantial evidence. It is undisputed that ETI’s test-year level of MSS-2 expense was too low. Every witness testifying on the issue recognized that the test-year amount is too small and should be updated based on more recent, actual payment information. ETI proffered evidence that by the time of the hearing, its annualized MSS-2 expenses based upon actual, known, historical investment exceeded test-year levels by about $6.7 million, and its rate-year MSS-2 expenses would exceed test- year levels by almost $9 million.131 TIEC witness Pollock annualized the last six months of the test-year expense, increasing it by a million dollars.132 Cities witness Goins also rejected the test-year expense level and instead used a more recent 12-month period of actual payments, including six months that occurred after the test year. He recommended the Commission include an annual expense of 131 AR Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Binder 43, Vol. F (4/27/12 Tr. at 738, 760, 763, 780, & 783-84). 132 AR Binder 41, TIEC Exh. 1 (Pollock Direct at 32-33). 42 $4.1 million in ETI’s rates, exceeding the test year by almost $2.5 million.133 Indeed, Cities Exhibit 29 includes the MSS-2 payment for every month from January 2010 to February 2012. It shows that MSS-2 costs have steadily increased every month from the last month of the test year, and in fact have doubled since the last month of the test year.134 No witness testified that the test year was representative of the expense ETI would bear during the rate year. The Commission’s decision that the test-year level of MSS-2 expense is sufficient is simply not supported by any evidence in the record. Viewing the evidence as a whole, there is no reasonable basis for a conclusion that the test-year level of $1.7 million is representative of costs apt to prevail in the future. The Commission’s ruling is, therefore, unsupported by substantial evidence and must be reversed. Tex. Gov’t Code Ann. § 2001.174(b)(2). CONCLUSION AND PRAYER For all these reasons, Entergy Texas, Inc. respectfully requests this Court reverse the district court’s judgment insofar as it affirms the Public Utility Commission’s order in the respects discussed above. ETI requests the Court remand the case to the Commission for further proceedings consistent with the 133 AR Binder 8, Cities Exh. 4 (Goins Direct at 21-22). 134 AR Binder 9, Cities Exh. 29 (Response of ETI to Cities RFI 5-1). 43 Court’s decision. Entergy Texas, Inc. further requests its costs of court and any other relief to which it may show itself justly entitled. Respectfully submitted, /s/ Marnie A. McCormick John F. Williams State Bar No. 21554100 Marnie A. McCormick State Bar No. 00794264 mmccormick@dwmrlaw.com DUGGINS WREN MANN & ROMERO, LLP P. O. Box 1149 Austin, Texas 78767-1149 (512) 744-9300 (512) 744-9399 fax ATTORNEYS FOR APPELLANT ENTERGY TEXAS, INC. CERTIFICATE OF COMPLIANCE I certify that this document contains 10,765 words in the portions of the document that are subject to the word limits of Texas Rule of Appellate Procedure 9.4(i), as measured by the undersigned’s word-processing software. /s/ Marnie A. McCormick Marnie A. McCormick 44 CERTIFICATE OF SERVICE The undersigned counsel certifies that the foregoing document was electronically filed with the Clerk of the Court using the electronic case filing system of the Court, and that a true and correct copy was served on the following lead counsel for all parties via electronic service on the 31st day of March, 2015: Elizabeth R. B. Sterling Environmental Protection Division Office of the Attorney General P. O. Box 12548 (MC 066) Austin TX 78711-2548 Counsel for Appellee Public Utility Commission of Texas Rex D. VanMiddlesworth Benjamin Hallmark Thompson Knight LLP 98 San Jacinto Blvd., Ste. 1900 Austin TX 78701 Counsel for Intervenor Texas Industrial Energy Consumers Susan M. Kelley (retired)135 Administrative Law Division Office of the Attorney General P. O. Box 12548 Austin TX 78711-2548 Counsel for Intervenor State Agencies Sara Ferris Office of Public Utility Counsel 1701 N. Congress Ave., Ste. 9-180 P. O. Box 12397 Austin TX 78711-2397 Counsel for Intervenor Office of Public Utility Counsel 135 State Agencies have not yet appeared or designated a new lead counsel in this appeal. 45 Daniel J. Lawton LAWTON LAW FIRM PC 12600 Hill Country Blvd., Ste. R-275 Austin TX 78738 Counsel for Cities of Anahuac, et al. /s/ Marnie A. McCormick Marnie A. McCormick 46 APPENDICES A. ALJs’ Proposal for Decision in Docket No. 39896 B. Commission's Order on Rehearing in Docket No. 39896 C. District Court's Final Judgment D. Commission’s Final Order in Docket No. 37744 47 APPENDIX A ALJ's Proposal for Decision in Docket No. 39896 SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE INC. FOR AUTHORITY TO CHANGE § RATES, RECONCILE FUEL COSTS, § OF AND OBTAIN DEFERRED § ACCOUNTING TREATMENT § ADMINISTRATIVE HEARINGS PROPOSAL FOR DECISION TABLE OF CONTENTS I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4]........ 1 II. JURISDICTION AND NOTICE ......................................................................... 2 III. PROCEDURAL HISTORY ................................................................................. 2 IV. EXECUTIVE SUMMARY .................................................................................. 4 A. Rate Base................................................................................................................ 4 1. Capital Investment .................................................................................... 4 2. Hurricane Rita Regulatory Asset ............................................................ 4 3. Prepaid Pension Asset Balance ................................................................ 5 4. FIN 48 Tax Adjustment ............................................................................ 5 5. Cash Working Capital .............................................................................. 5 6. Self-Insurance Storm Reserve ................................................................. 5 7. Coal Inventory........................................................................................... 5 8. Spindletop Gas Storage Facility .............................................................. 5 9. Short Term Assets ..................................................................................... 6 10. Acquisition Adjustment ............................................................................ 6 11. Capitalized Incentive Compensation ...................................................... 6 B. Rate of Return and Capital Structure ................................................................ 6 C. Cost of Service ....................................................................................................... 7 1. Purchased Power Capacity Expense ....................................................... 7 2. Transmission Equalization (MSS-2) Expense ........................................ 7 3. Depreciation Expense ............................................................................... 7 4. Labor Costs................................................................................................ 7 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE II PUC DOCKET NO. 39896 5. Interest on Customer Deposits................................................................. 8 6. Property (Ad Valorem) Tax Expense ...................................................... 9 7. Advertising, Dues, and Contributions..................................................... 9 8. Other Revenue Related Adjustments ...................................................... 9 9. Federal Income Tax .................................................................................. 9 10. River Bend Decommissioning Expense ................................................... 9 11. Self-Insurance Storm Reserve Expense .................................................. 9 12. Spindletop Gas Storage Facility ............................................................ 10 D. Affiliate Transactions ......................................................................................... 10 E. Jurisdictional Cost Allocation............................................................................ 10 F. Class Cost Allocation .......................................................................................... 11 1. Renewable Energy Credit Rider............................................................ 11 2. Class Cost Allocation .............................................................................. 11 3. Revenue Allocation ................................................................................. 12 4. Rate Design .............................................................................................. 12 G. MISO Transition ................................................................................................. 14 V. RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16] ...... 14 A. Capital Investment [Germane to Preliminary Order Issue No. 17] ............... 14 B. Hurricane Rita Regulatory Asset ...................................................................... 15 C. Prepaid Pension Asset Balance .......................................................................... 23 D. FIN 48 Tax Adjustment ...................................................................................... 26 E. Cash Working Capital ........................................................................................ 30 1. The Revenue Lag Component of the Lead-Lag Study ........................ 31 2. The Expense Lead Component of the Lead-Lag Study ....................... 39 F. Self-Insurance Storm Reserve [Germane to Preliminary Order Issue No. 5] .................................................................................................................... 45 1. The Effect of Prior Settled Cases........................................................... 46 2. OPC’s Proposed Adjustment ................................................................. 49 3. 1997 Ice Storm ......................................................................................... 54 4. Jurisdictional Separation Plan Allocation ............................................ 57 5. $50,000 Reserve Threshold .................................................................... 58 6. Hurricane Rita Regulatory Asset .......................................................... 60 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE III PUC DOCKET NO. 39896 7. Conclusion ............................................................................................... 60 G. Coal Inventory..................................................................................................... 61 H. Spindletop Gas Storage Facility ........................................................................ 63 I. Short Term Assets ............................................................................................... 68 J. Acquisition Adjustment ...................................................................................... 69 K. Capitalized Incentive Compensation ................................................................ 71 VI. RATE OF RETURN [Germane to Preliminary Order Issue Nos. 4 and 11] ......................................................................................................................... 73 A. Capital Structure ................................................................................................ 73 B. Return on Equity................................................................................................. 73 1. Proxy Group ............................................................................................ 74 2. DCF Analysis ........................................................................................... 76 3. Risk Premium Analysis .......................................................................... 83 4. Comparable Earnings............................................................................. 88 5. CAPM Analysis ....................................................................................... 90 6. ALJs’ Analysis......................................................................................... 93 C. Cost of Debt ......................................................................................................... 95 D. Overall Rate of Return ....................................................................................... 95 VII. OPERATING EXPENSES [Germane to Preliminary Order Issue Nos. 2, 3, 4, and 16] .......................................................................................................... 95 A. Purchased Power Capacity Expense [Germane to Supplemental Preliminary Order Issue No. 1] ......................................................................... 95 1. The Sources of ETI’s Purchased Power................................................ 95 2. ETI’s Request Regarding PPCCs .......................................................... 99 3. Staff and Intervenors’ Opposition to ETI’s PPCCs Proposal .......... 101 4. The Intervenors’ Recommendations Regarding PPCCs ................... 106 5. The ALJs’ Analysis Regarding PPCCs ............................................... 108 B. Transmission Equalization (MSS-2) Expense ................................................ 110 C. Depreciation Expense [Germane to Preliminary Order Issue No. 12] ........ 117 1. Terminology and Methodology............................................................ 118 2. Production Plant ................................................................................... 125 3. Transmission Plant ............................................................................... 132 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE IV PUC DOCKET NO. 39896 4. Distribution Plant ................................................................................. 140 5. General Plant......................................................................................... 154 6. Fully Accrued Depreciation ................................................................. 160 7. Other Depreciation Issues – Accumulated Provision for Depreciation .......................................................................................... 161 D. Labor Costs........................................................................................................ 163 1. Payroll and Related Adjustments ........................................................ 163 2. Incentive Compensation ....................................................................... 165 3. Compensation and Benefits Levels ...................................................... 175 4. Non-Qualified Executive Retirement Benefits ................................... 177 5. Employee Relocation Costs .................................................................. 179 6. Executive Perquisites ............................................................................ 180 E. Interest on Customer Deposits......................................................................... 181 F. Property (Ad Valorem) Tax Expense .............................................................. 181 G. Advertising, Dues, and Contributions............................................................. 185 H. Other Revenue-Related Adjustments ............................................................. 185 I. Federal Income Tax .......................................................................................... 185 J. River Bend Decommissioning Expense ........................................................... 186 K. Self-Insurance Storm Reserve Expense [Germane to Preliminary Order Issue No. 5]......................................................................................................... 188 L. Spindletop Gas Storage Facility ...................................................................... 193 VIII. AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue No. 3] .................................................................................................................. 194 A. Large Industrial & Commercial Sales Reallocation ...................................... 199 B. Administration Costs ........................................................................................ 201 C. Customer Service Operations Class ................................................................ 202 1. Projects F3PCR29324 (Revenue Assurance - Adm.), F3PCR53095 (Headquarter’s Credit & Collect), F3PCR73380 (Credit Systems), and F3PCR73458 (Credit Call Outsourcing) .................... 202 2. Projects F3PCR73381 (Customer Svc Cntr Credit Desk), F3PCR73390 (Customer Svs Ctl - Entergy Bus), and F3PCR73403 (Customer Issue Resolution – ES) ............................... 203 D. Distribution Operations Class ......................................................................... 203 1. Project F5PCDW0200 (Lineman’s Rodeo Expenses) ........................ 204 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE V PUC DOCKET NO. 39896 2. Projects F3PCTJGUSE (Joint Use With Third Party – E) and F3PCTJTUSE (Joint Use With Third Parties – A)............................ 204 E. Energy and Fuel Management Class .............................................................. 205 1. Project F3PCWE0140 (EMO Regulatory Affairs) ............................ 205 2. Projects F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE004 (SPO Summer09RFP IM & Propslsubmt), and F3PPWET303 (SPO2008 Winter Westn RegionRFP-IM) ......................................... 206 3. Project F3PCCSPSYS (System Planning and Strategic) .................. 207 F. Environmental Service Class ........................................................................... 207 G. Federal PRG Affairs Class ............................................................................... 209 1. Project F5PPSPE044 (PMO Support Initiative-System) .................. 209 2. Project F3PPUTLDER (Utility Derivatives Compliance) ................. 210 3. Project F3PCSYSRAF (System Regulatory Affairs-Federal) .......... 211 H. Financial Services Class ................................................................................... 214 1. Projects F3PCF05700 (Corporate Planning & Analysis), F3PCF21600 (Corp Rptg Analysis & Policy), F3PCFF1000 (Financial Forecasting), F3PPADSENT (Analytic/Decision Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs- Entergy) ................................................................................................. 214 2. Projects F3PCF20990 (Operations Exec VP & CFO) and F3PCFF1001 (OCE Support)............................................................... 215 3. Project F3PCR73345 (Quick Payment Center, Adm) ....................... 216 4. Project F3PCF23936 (Manage Cash) .................................................. 217 I. Human Resources Class ................................................................................... 218 1. Project F3PCHRCCSM (HR Competitive Compensation) .............. 218 2. Projects (Non-Qualified Post-Retirement) and F5PPZNQBDU (Non-Qual Pension/Benf-Dom Utl)...................................................... 219 J. Information Technology Class ......................................................................... 219 1. (Evaluated Receipts Settlement) ......................................................... 220 2. Project F3PCFX3555 (BOD/Executive Support) ............................... 220 K. Internal and External Communications Class ............................................... 221 L. Legal Services Class .......................................................................................... 222 1. Project F3PPCASHCT (Contractual Alternative/Cashpo) .............. 223 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE VI PUC DOCKET NO. 39896 2. Project F5PCZLDEPT (Supervision & Support – Legal)................. 223 3. Project F3PCF99180 (Corp. Compliance Tracking Sys) .................. 223 4. Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and F3PPTDHY19 (Dept. of Justice Investigation) .................................. 224 5. Project F3PCE01601 (Ferc - Access Transmission) ......................... 226 6. Project F3PCERAKTL (RAKTL Patent Matter) ............................. 227 7. Project F3PPEASTIN (Willard Eastin et al.) ..................................... 228 8. Project F3PPTCGS11 (TX Docket Competitive Generation) .......... 229 9. Project F5PCE13759 (Jenkins Class Action Suit) ............................. 230 10. Project F3PCSYSAGR (System Agreement-2001) ............................ 231 11. Project F3PCCDVDAT (Corporate Development Data Room) ....... 232 12. Project F3PPWET302 (SPO 2008 Winter Western Region) ............ 233 13. Project F3PPWET308 (SPO Calpine PPA/Project Houston) ........... 234 M. Other Expenses Class ....................................................................................... 235 1. Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and F5PPKATRPT (Storm Cost Processing & Review) .......................... 235 2. Project F3PCC08500 (Executive VP, Operations)............................. 236 3. Projects F3PPBFMESI (ESI Function Migration Relocation), F3PPBFRESI (ESI Business Function ), F3PPDRPESI (ESI Disaster Recovery Plan Charge), F5PPBFMREL (Business Function Migration Employee), F5PPBFRREL (Business Function Relocation), F5PPBFRSEV (Business Function Relocation Severance), F5PPDRPREL (Disaster Recovery Plan Relocation), and F5PPETXRFI (2009 Texas Ike Recovery Filing) .. 236 N. Regulatory Services Class ................................................................................ 238 O. Retail Operations Class .................................................................................... 239 1. Project F5PPICCIMG (ICC – “Image” Message) ............................. 240 2. Projects F3PPR56640 (Wholesale - EGS-TX) and F3PPR56920 (Wholesale - All Jurisdictions) ............................................................. 240 P. Supply Chain Class ........................................................................................... 241 Q. Transmission and Distribution Support Class ............................................... 242 R. Tax Services Class ............................................................................................. 244 S. Transmission Operations Class ....................................................................... 245 T. Treasury Operations Class .............................................................................. 246 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE VII PUC DOCKET NO. 39896 U. Utility and Executive Management Class ....................................................... 249 IX. JURISDICTIONAL COST ALLOCATION [Germane to Preliminary Order Issue No. 13] ........................................................................................... 250 A. A&E 4CP ........................................................................................................... 251 B. 12CP ................................................................................................................... 252 X. CLASS COST ALLOCATION AND RATE DESIGN [Germane to Preliminary Order Issue No. 1] ....................................................................... 255 A. Renewable Energy Credit Rider [Germane to Preliminary Order Issue No. 19] ................................................................................................................ 255 1. ETI’s Proposed Cost Recovery ............................................................ 255 2. Opposition to ETI’s Proposal .............................................................. 256 3. ETI’s Response ...................................................................................... 260 4. ALJs’ Analysis....................................................................................... 261 B. Class Cost Allocation [Germane to Preliminary Order Issue No. 14] ......... 262 1. Municipal Franchise Fees .................................................................... 262 2. Miscellaneous Gross Receipts Taxes ................................................... 267 3. Capacity-Related Production Costs .................................................... 268 4. Transmission Costs ............................................................................... 273 C. Revenue Allocation ........................................................................................... 274 1. Argument for Moving Rates to Cost ................................................... 275 2. Argument for Gradualism ................................................................... 278 3. ALJs’ Recommendation ....................................................................... 281 D. Rate Design [Germane to Preliminary Order Issue Nos. 15, 18, and 20] .... 282 1. Lighting and Traffic Signal Schedules ................................................ 283 2. Demand Ratchet .................................................................................... 287 3. Large Industrial Power Service (LIPS) .............................................. 295 4. Schedulable Intermittent Pumping Service (SIPS)............................ 299 5. Standby Maintenance Service (SMS) .................................................. 303 6. Additional Facilities Charge (AFC) .................................................... 310 7. Large General Service (LGS) .............................................................. 313 8. General Service (GS) ............................................................................ 315 9. Residential Service (RS) ....................................................................... 315 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE VIII PUC DOCKET NO. 39896 XI. FUEL RECONCILIATION [Germane to Preliminary Order Issue Nos. 21-31] ......................................................................................................... 319 A. Spindletop Gas Storage Facility ...................................................................... 324 B. Use of Current Line Losses for Fuel Cost Allocation .................................... 325 C. ETI’s Special Circumstances Request ............................................................ 326 XII. OTHER ISSUES ............................................................................................... 327 A. MISO Transition Expenses [Germane to Preliminary Order Issue Nos. 6-8 and Docket No. 39741 Preliminary Order Issue Nos. 1-9] ............. 327 1. Deferred Accounting............................................................................. 329 2. Base Rate Recovery............................................................................... 336 B. TCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2] .................................................................................................................. 338 C. DCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2] .................................................................................................................. 338 D. Purchased Power Capacity Cost Baseline [Germane to Supplemental Preliminary Order Issue No. 1] ....................................................................... 339 XIII. CONCLUSION ................................................................................................. 341 XIV. PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND ORDERING PARAGRAPHS .......................................................................... 341 A. Findings of Fact ................................................................................................. 341 B. Conclusions of Law ........................................................................................... 364 C. Proposed Ordering Paragraphs ...................................................................... 366 List of Acronyms and Defined Terms Attachment A List of Acronyms and Defined Terms TERM DEFINITION 12CP 12 Coincident Peak A&E 4CP Average and Excess, 4 Coincident Peak A&P Average and Single Coincident Peak ADFIT Accumulated Deferred Federal Income Tax AFC Additional Facilities Charge AFUDC Allowance for Funds Used During Construction ALJs Administrative Law Judges BCII/U3 Big Cajun II, Unit 3 Brazos Brazos Electric Cooperative, Inc. Calpine Calpine Energy Services Contract for the purchase of 485 MW of capacity from Carville Contract Calpine’s Carville Energy Center CAPM Capital Asset Pricing Model CenterPoint CenterPoint Energy Houston Electric, LLC CGS Competitive Generation Service CI Conformance Index Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and Cities West Orange, Texas Commission Public Utility Commission of Texas Company Entergy Texas, Inc. CP Coincident Peak CWIP Construction Work in Progress DCF Discounted Cash Flow DCRF Distribution Cost Recovery Factor DOE United States Department of Energy DOJ United States Department of Justice EAI Entergy Arkansas, Inc. EA WBL 2009 Contract between ETI and EAI for Wholesale Base Contract Load Resources EGSI Entergy Gulf States, Inc., predecessor to ETI EGSL Entergy Gulf States Louisiana, LLC ELL Entergy Louisiana, Inc. EMI Entergy Mississippi, Inc. Enbridge Long-term Gas Supply Contract between ETI and Enbridge Contract Pipeline, L.P. ENOI Entergy New Orleans, Inc. Entergy Entergy Corporation TERM DEFINITION ESI Entergy Services, Inc. ETEC East Texas Electric Cooperative, Inc. ETI Entergy Texas, Inc. FAS 106 FASB Statement No. 106 FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission FIN 48 Financial Interpretation Number 48 GAAP Generally Accepted Accounting Principles GDP Gross Domestic Product GS General Service GSU Gulf States Utilities Company Iowa Curves Various Known Patterns of Industrial Asset Mortality Rates IRS Internal Revenue Service ISB Intra-System Bill Class action lawsuit filed in Texas district court in 2003 on Jenkins Class behalf of all Texas retail customers served by ETI’s Action predecessor-in-interest, EGSI Kroger The Kroger Co. kW Kilowatt kWh Kilowatt-hour LED Light Emitting Diode LGS Large General Service LIPS Large Industrial Power Service MFF Municipal Franchise Fees MGRT Miscellaneous Gross Receipts Tax MISO Midwest Independent Transmission System Operator, Inc. MSS-2 Schedule MSS-2 of the Entergy System Agreement MW Megawatt Moody’s Moody’s Investors Service MWh Megawatt-hour NARUC National Association of Regulatory Utility Commissioners Nelson Nelson 6, a 550 MW Unit located in Westlake, Louisiana O&M Operations and Maintenance OATT Open Access Transmission Tariff OPC Office of Public Utility Counsel PFD Proposal for Decision PPCCs Purchased Power Capacity Costs PPR Purchased Power Rider PUC Public Utility Commission of Texas PURA Public Utility Regulatory Act Rate Year June 1, 2012, through May 31, 2013 Reconciliation Period July 1, 2009, through June 30, 2011 TERM DEFINITION RECs Renewable Energy Credits Reserve Strategic Petroleum Reserve River Bend River Bend Nuclear Generating Station Unit No. 1 ROE Return on Equity RRC Railroad Commission of Texas RS Residential Service RTO Regional Transmission Organization S&P Standard & Poor’s SFAS Statement of Financial Accounting Standards SIPS Schedulable Intermittent Pumping Service SMS Standby Maintenance Service SOAH State Office of Administrative Hearings Spindletop Facility Spindletop Gas Storage Facility SRMPA Sam Rayburn Municipal Power Agency Staff Staff of the Public Utility Commission of Texas State Agencies State of Texas State Agencies T&D Transmission and Distribution TCRF Transmission Cost Recovery Factor Test Year July 1, 2010, through June 30, 2011 TIEC Texas Industrial Energy Consumers Value Line Value Line Investment Survey Wal-Mart Wal-Mart Stores, LLC, and Sam’s East, Inc. Zacks Zacks Investment Service SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE INC. FOR AUTHORITY TO CHANGE § RATES, RECONCILE FUEL COSTS, § OF AND OBTAIN DEFERRED § ACCOUNTING TREATMENT § ADMINISTRATIVE HEARINGS PROPOSAL FOR DECISION I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4] Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail service area located in southeastern Texas. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI served approximately 412,000 Texas retail customers. The Federal Energy Regulatory Commission (FERC) regulates ETI’s wholesale electric operations. On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed increase in annual base rate revenues of approximately $111.8 million over adjusted revenues for the period beginning July 1, 2010, and ending June 30, 2011 (Test Year); (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities accompanying ETI’s application and including new riders for recovery of costs related to purchased power capacity and renewable energy credit requirements; (3) a request for final reconciliation of ETI’s fuel and purchased power costs for the reconciliation period from July 1, 2009, to June 30, 2011 (Reconciliation Period); and (4) certain waivers to the instructions in Rate Filing Package Schedule V accompanying ETI’s application. The rate year for ETI’s proposed changes is June 1, 2012, through May 31, 2013 (Rate Year).1 On April 13, 2012, adjusted its request for a proposed increase in annual base rate revenues to approximately $104.8 million over adjusted Test Year revenues. 1 During the hearing the parties used the term “Rate Year” to refer to the period June 2012 through May 2013. This was intended to represent the first 12 months of the rates adopted in this case. However, the rates in this case will not go into effect (as temporary rates) until at least June 30, 2012. Nevertheless, for purposes of this PFD, Rate Year will refer to the period June 2012 through May 2013. SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 2 PUC DOCKET NO. 39896 II. JURISDICTION AND NOTICE The Public Utility Commission of Texas (Commission or PUC) has jurisdiction over ETI and this rate case application pursuant to Public Utility Regulatory Act (PURA) §§ 14.001, 32.001, 33.002, and 35.004. The State Office of Administrative Hearings (SOAH) has jurisdiction over the contested case hearing, including the preparation of the proposal for decision (PFD) pursuant to PURA § 14.053 and Tex. Gov’t Code § 2003.049(b). Those municipalities in ETI’s service area that have not surrendered jurisdiction to the Commission continue to have exclusive original jurisdiction over ETI’s rates, operations, and services in their respective municipalities pursuant to PURA § 33.001. When ETI filed its application with the Commission, it also filed the application with its original jurisdiction cities. Pursuant to PURA §§ 32.001(b), 33.051, and 33.053, ETI appealed the actions of the original jurisdiction cities to the Commission and had those appeals consolidated with this docket. ETI’s notice of its application and notice of the hearing were not contested and, therefore, do not require further discussion but will be addressed in the proposed findings of fact and conclusions of law. III. PROCEDURAL HISTORY As noted above, ETI filed its application and rate filing package on November 28, 2011. On November 29, 2011, the Commission referred this proceeding to SOAH. On December 19, 2011, the Commission issued its Preliminary Order setting forth 31 issues to be addressed in this proceeding. On January 19, 2012, the Commission issued a Supplemental Preliminary Order listing two additional issues to be considered and stating that ETI’s request for a purchased power cost recovery rider should not be addressed in this docket. On September 2, 2011, ETI filed an application requesting authority to defer accounting related to its proposed transition to membership in the Midwest Independent Transmission System Operator, Inc. (MISO). This proceeding was docketed as Docket No. 39741. On November 22, 2011, the Commission issued its Preliminary Order in Docket No. 39741 addressing certain SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 3 PUC DOCKET NO. 39896 threshold legal/policy questions and setting forth nine issues to be addressed in the proceeding. On December 20, 2011, Docket No. 39741 was consolidated into this docket for all purposes. The following entities were granted intervenor status in this case: Texas Industrial Energy Consumers (TIEC); State of Texas State Agencies (State Agencies); Office of Public Utility Counsel (OPC); the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge Nor [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/cases/4062185. Public record. Not legal advice.