# 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/4062193 ## 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/4062193 ## Opinion text ACCEPTED 03-14-00735-CV 4711647 THIRD COURT OF APPEALS AUSTIN, TEXAS 3/31/2015 2:04:20 PM JEFFREY D. KYLE CLERK FILED IN NO. 03-14-00735-CV 3rd COURT OF APPEALS AUSTIN, TEXAS 3/31/2015 2:04:20 PM JEFFREY D. KYLE Clerk ENTERGY TEXAS, INC., ET AL., Appellants, v. PUBLIC UTILITY COMMISSION OF TEXAS, INC., ET AL., Appellees. B RIEF OF A PPELLANT Filed by: Public Utility Commission of Texas KEN PAXTON JON NIERMANN Attorney General of Texas Chief, Environmental Protection Division CHARLES E. ROY First Assistant Attorney General ELIZABETH R. B. STERLING Assistant Attorney General JAMES E. DAVIS State Bar No. 19171100 Deputy Attorney General for elizabeth.sterling@texasattorneygeneral.gov Civil Litigation Environmental Protection Division P.O. Box 12548, MC-066 Austin, Texas 78711-2548 512.463.2012 512.457.4616 (fax) March 31, 2015 Oral Argument Requested Identity of Parties and Counsel Party Counsel Entergy Texas, Inc., Plaintiff in the Marnie A. McCormick district court, Appellant and Patrick J. Pearsall Appellee in this Court Duggins Wren Mann & Romero, LLP P. O. Box 1149 Austin, Texas 78767-1149 512.744.9300 512.744.9399 (fax) mmccormick@dwmrlaw.com ppearsall@dwmrlaw.com Cities of Anahuac, Beaumont, Daniel J. Lawton Bridge City, Cleveland, Conroe, The Lawton Law Firm, P.C. Dayton, Groves, Houston, 12600 Hill Country Blvd., Huntsville, Montgomery, Navasota, Ste. R-275 Nederland, Oak Ridge North, Austin, TX 78738 Orange, Pine Forest, Rose City, 512.322.0019 Pinehurst, Port Arthur, Port 855.298.7978 (fax) Neches, Shenandoah, Silsbee, Sour dlawton@ecpi.com Lake, Splendora, Vidor, and West (in district court, also Stephen Orange, Plaintiffs in the district Mack) court and Interested Parties before this Court Office of Public Utility Counsel, Sara J. Ferris Plaintiff in the district court and Assistant Public Counsel Appellant before this Court Office of Public Utility Counsel P.O. Box 12397 Austin, Texas 78711-2397 512.936.7500 512.936.7520 (fax) sara.ferris@opuc.texas.gov i State Agencies, Plaintiffs in the Katherine H. Farrell district court and Interested Parties Assistant Attorney General before this Court Administrative Law Division Energy Rates Section Office of the Attorney General P.O. Box 12548, MC 018-12 Austin, Texas 78711-2548 512.475.4237 512.320.0167 (fax) katherine.farrell@texasattorneygen eral.gov (in district court, Susan M. Kelley and Bryan L. Baker) Texas Industrial Energy Rex VanMiddlesworth Consumers, Intervenors in the Benjamin Hallmark district court and Interested Parties Thompson & Knight LLP before this Court 98 San Jacinto Blvd., Ste. 1900 Austin, Texas 78701 512.469.6100 512.469.6180 (fax) rex.vanm@tklaw.com benjamin.hallmark@tklaw.com (in district court, Meghan Griffiths at Andrews Kurth LLP) ii Public Utility Commission of Texas, Ken Paxton Defendant in the district court, Attorney General of Texas Appellant and Appellee before this (in district court, Greg Abbott) Court Charles E. Roy First Assistant Attorney General (in district court, Daniel Hodge) James E. Davis Deputy Attorney General for Civil Litigation (in district court, John B. Scott) Jon Niermann Chief, Environmental Protection Division Assistant Attorneys General: Elizabeth R. B. Sterling John R. Hulme Daniel C. Wiseman Megan Neal Environmental Protection Division Office of the Attorney General P.O. Box 12548, MC-066 Austin, Texas 78711-2548 512.463.2012 512.457.4616 (fax) iii Table of Contents Identity of Parties and Counsel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i Table of Contents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv Index of Authorities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii Glossary.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix Statement of the Case. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi Statement Regarding Oral Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi Issue Presented. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi In a Fuel Reconciliation, the Commission determines the actual reasonable and necessary amount that a utility spent on fuel expenses. Do the Commission’s rules allow it to use a contemporaneous line-loss study to determine how much electricity was lost from the generator to the end user so that the Commission can accurately determine how much the utility had to spend on fuel to generate electricity for retail customers? .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi Statement of Facts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 A. The Commission uses a two-step process for a utility to recover fuel expenses: first the Commission sets a temporary rate called a fuel factor, and later the Commission conducts a Fuel Reconciliation where the actual fuel expenses that the utility may recover from ratepayers are finally determined.. . . . . . . . . . . . . . . . . . . . . . . . . 1 B. Entergy asked to reconcile fuel expenses for July 2009 through June 2011, but wanted to use an old 1997 line- loss study rather than the contemporaneous 2010 line- loss study.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 iv 1. Entergy asked to reconcile fuel expenses for a two- year period from July 2009 through June 2011.. . . . . . . 3 2. Because some electricity is lost as it travels over wires, the utility must perform a line-loss study to account for the total amount that must be generated to meet demand... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 C. Cities argued that the contemporaneous line-loss study would show actual fuel costs incurred during the reconciliation period, and that contemporaneous line-loss study showed that $4 million of fuel costs Entergy assigned to retail ratepayers were incurred to serve wholesale customers... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 D. The Commission decided that the contemporaneous line- loss study should be used... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 E. Three Commission rules apply to a utility’s recovery of fuel expenses: Rule 25.235, Rule 25.236, and Rule 25.237... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 F. The district court reversed the Commission’s decision about using the contemporaneous line-loss study.. . . . . . . . . . 9 Summary of the Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 A. Standard of Review. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 B. The Commission’s Order complies with its rules. . . . . . . . . . . 12 1. Rule 25.236(d) applies to this Fuel Reconciliation and authorizes the Commission’s decision.. . . . . . . . . . . 12 2. None of the rules cited by the district court apply to the Fuel Reconciliation in this case... . . . . . . . . . . . . . . . . 14 v a. Rule 25.236(e)(3) does not apply to this Fuel Reconciliation.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 b. Rule 25.237(a) does not apply to a Fuel Reconciliation.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 c. Rule 25.237(c)(2)(B) does not apply to a Fuel Reconciliation.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 C. Entergy has not shown prejudice to its substantial rights.. . . . 18 Conclusion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Prayer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Certificate of Compliance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Certificate of Service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 APPENDICES District Court Judgment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A Commission Order.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B ALJ’s Proposal for Decision. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C Entergy’s Statement of Intent and Application for Authority to Change Rates and Reconcile Fuel Costs (pages 1–12). . . . . . . . . . . . . . . . . . . . D Rules: 16 Tex. Admin. Code § 25.235.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E 16 Tex. Admin. Code § 25.236. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F 16 Tex. Admin. Code § 25.237.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . G vi Index of Authorities Cases Page(s) CenterPoint Energy Houston Elec., LLC v. Pub. Util. Comm’n, 212 S.W.3d 389 (Tex. App.—Austin 2006, pet. granted, judgm’t vacated w.r.m.).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 El Paso Elec. Co. v. Pub. Util. Comm’n, 917 S.W.2d 846 (Tex. App.—Austin 1995, writ dism’d by agr.).. . . 18 Gulf States Utils. Co. v. Pub. Util. Comm’n, 841 S.W.2d 459 (Tex. App.—Austin 1992, writ denied).. . . . . . . . . 19 Lewis v. Jacksonville Bldg. & Loan Ass’n, 540 S.W.2d 307 (Tex. 1976). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Pub. Util. Comm’n v. Gulf States Utils. Co., 809 S.W.2d. 201 (Tex. 1991). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Pub. Util. Comm’n v. Tex. Utils. Elec. Co., 935 S.W.2d 109 (Tex. 1997). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 RepublicBank Dallas, N.A. v. Interkal, Inc., 691 S.W.2d 605 (Tex. 1985). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Rodriguez v. Serv. Lloyds Ins. Co., 997 S.W.2d 248 (Tex. 1999). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Sw. Pharmacy Solutions, Inc. v. Tex. Health and Human Servs., 408 S.W.3d 549 (Tex. App.—Austin 2013, pet. denied). . . . . . . . . 11 State v. Pub. Util. Comm’n, 883 S.W.2d 190 (Tex. 1994). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Tex. Bd. Of Chiropractic Exam’rs v. Tex. Med. Ass’n, 375 S.W.3d 464 (Tex. App.—Austin 2012, pet. denied).. . . . . . 11, 12 vii Cases cont’d Page(s) Tex. Utils. Elec. Co. v. Pub. Util. Comm’n, 881 S.W.2d 387 (Tex. App.—Austin 1994). . . . . . . . . . . . . . . . . . . . . 1 Statutes Tex. Gov’t Code §§ 2001.001–.902. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix § 2001.174(2). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Rules 16 Tex. Admin. Code §§ 25.235-25.237.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 § 25.236(b).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix § 25.236(d).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 § 25.236(d)(1)(A).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13, 19 § 25.236(d)(2). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2, 8, 9, passim § 25.236(e)(3). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 § 25.237(a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 § 25.237(a)(1).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5, 16 § 25.237(a)(3). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix, 3, 9 § 25.237(a)(3)(A).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 § 25.237(a)(3)(B).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 § 25.237(c)(2)(B).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16, 17 viii Glossary ALJ Administrative Law Judge APA Administrative Procedure Act, Tex. Gov’t Code §§ 2001.001–.902. Cities Cities of 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 West Orange, Texas These cities are in the service area of Entergy Texas, Inc. Commission or PUC Public Utility Commission of Texas Entergy Entergy Texas, Inc., the utility that asked the Commission to reconcile fuel expenses in this case ERCOT Electric Reliability Council of Texas Fuel Factor A temporary rate set by the Commission to recover the utility’s fuel costs See 16 Tex. Admin. Code § 25.237(a)(3). Fuel Reconciliation After the utility has collected for fuel costs using the Fuel Factor, it returns to the Commission to reconcile actual fuel costs with amounts recovered under the Fuel Factor. See 16 Tex. Admin. Code § 25.236(b). Line Losses Electricity that the utility generates but is “lost” as it travels along the wires from the generator to the customer; more electricity is generated than is metered where it is used Order The Commission’s order on rehearing that is the subject of this lawsuit. (AR, Item 244.) ix PFD Proposal for Decision prepared by the ALJ in this case (AR, Item 185.) x Statement of the Case Entergy Texas, Inc., an electric utility in the southeastern part of the state, together with several groups of its customers, filed an administrative appeal of the Public Utility Commission’s order setting rates for Entergy. The district court affirmed the Commission’s order on all but one issue. The Commission appeals on that issue; several other parties are appealing different issues. Statement Regarding Oral Argument Each of the three appellants in this rate case bring separate issues. Looking at the entire case, the number of parties, the number of issues, and the complexity of many of the issues, oral argument would help the Court. Issue Presented In a Fuel Reconciliation, the Commission determines the actual reasonable and necessary amount that a utility spent on fuel expenses. Do the Commission’s rules allow it to use a contemporaneous line-loss study to determine how much electricity was lost from the generator to the end user so that the Commission can accurately determine how much the utility had to spend on fuel to generate electricity for retail customers? xi Statement of Facts Although the Commission set base rates and determined a Fuel Reconciliation in its Order, the Commission’s sole appellant’s issue concerns Entergy fuel costs for retail service. A. The Commission uses a two-step process for a utility to recover fuel expenses: first the Commission sets a temporary rate called a fuel factor, and later the Commission conducts a Fuel Reconciliation where the actual fuel expenses that the utility may recover from ratepayers are finally determined. Because fuel costs are so volatile and such a large part of an electric utility’s expenses,1 the Commission sets a temporary rate called a Fuel Factor but determines the actual amount that the utility should have recovered for fuel expenses in a later Fuel Reconciliation. The practice is so long-standing that this Court recognized it in a 1994 case that discussed reconciling fuel costs dating back to 1983. See Tex. Utils. Elec. Co., v. Pub. Util. Comm’n , 881 S.W.2d 387, 411–12 (Tex. App.—Austin 1994) aff’d in 1 For example, in this case, Entergy estimated that its over-recovery balance was $243,339,353. SAR, Item 1 at 9. The administrative record in this case was admitted into evidence as Joint Exhibits Nos. 1 through 13. R.R. at 5:11–5:19. Exhibits 1–3 are indices to the administrative record. Exhibits 4–10 and 13 include seven volumes of filings, which are referenced as “item”; thirty-five volumes of exhibits; and one transcript. Citations to that part of the Administrative Record will be in the form “AR, Item(s) ___,” for filings, “AR, ___ Ex(s). ___,” for exhibits, and “AR, Tr. at ___” for transcripts. Exhibits 11 and 12 contain Entergy’s entire rate-filing package. They are two boxes containing six items numbered 1–6. Because different documents are numbered 1–6 in the other parts of the administrative record, citations to the Supplemental Administrative Record will be in the form “SAR, Item(s) ___.” 1 part, rev’d in part sub nom. Pub. Util. Comm’n v. Tex. Utils. Elec. Co., 935 S.W.2d 109 (Tex. 1997). This Court explained: “Fuel reconciliation is a term used to describe periodic adjustments to a utility’s fuel costs made to account for the difference between previously anticipated costs and actual, reasonable costs incurred. The Commission makes these adjustments on a periodic basis because of the practical difficulty of deciding a new rate case with each variation in fuel prices.” The two-step process allows the utility to recover its reasonable fuel expenses and not over-recover for those costs.2 Without the Fuel Factor followed by a reconciliation, either the utility might lose a significant amount because the rates in place assumed much too low a fuel cost or the ratepayers might have paid exorbitant rates because the rates in place assumed much too high a fuel price. And if fuel costs were included in regular rates, the rule against retroactive ratemaking would prohibit the Commission from determining whether the utility had recovered too much or too little.3 The Commission avoids these problems 2 16 Tex. Admin. Code § 25.236(d)(2) (“The scope of a fuel reconciliation proceeding includes any issue related to determining the reasonableness of the electric utility’s fuel expenses during the reconciliation period and whether the electric utility has over- or under-recovered its reasonable fuel expenses.”). 3 The rule against retroactive ratemaking “prohibits a utility commission from making a retrospective inquiry to determine whether a prior rate was reasonable and imposing a surcharge when rates were too low or a refund when rates were too high.” State v. Pub. Util. Comm’n, 883 S.W.2d 190, 199 (Tex. 1994). 2 by setting a temporary rate called a Fuel Factor.4 Periodically, the utility returns for a Fuel Reconciliation, where the Commission reconciles the amounts the utility received under the Fuel Factor with the actual, reasonable expenses it incurred for fuel to generate electricity for retail customers. The utility can then ask to refund any over-recovery or surcharge any under-recovery.5 In effect, the Fuel Factor is a forward- looking, estimated rate and the reconciliation determines the actual rate. B. Entergy asked to reconcile fuel expenses for July 2009 through June 2011, but wanted to use an old 1997 line-loss study rather than the contemporaneous 2010 line-loss study. 1. Entergy asked to reconcile fuel expenses for a two-year period from July 2009 through June 2011. Entergy’s application to change rates and reconcile fuel costs6 (its “pleading” before the Commission) includes several statements important to this appeal. 4 See 16 Tex. Admin. Code § 25.237(a)(3). 5 16 Tex. Admin. Code § 25.237(a)(3)(A) (“The reasonableness of the fuel costs that an electric utility has incurred will be periodically reviewed in a reconciliation proceeding, as described in §25.236 of this title, and any disallowed costs resulting from a reconciliation proceeding will be reflected in the calculation of the utility’s recoverable fuel and over/(under) collections.”). 6 SAR, Item 1. A copy without exhibits is attached as Appendix D. 3 • Entergy asked, pursuant to Rule 25.236 to reconcile its fuel and purchased power costs to its Fuel Factor revenues during the Reconciliation Period,7 but Entergy did not ask to change its Fuel Factor. • Entergy’s Reconciliation Period for this case is a two-year period—July 2009 through June 2011.8 • Entergy’s fuel-reconciliation request applies only to retail customers: “This Application will affect all of [Entergy]’s retail customers taking service under its fixed fuel factor (‘Schedule FF’) by reconciling the fuel and purchased power costs incurred and the fuel factor revenue received in providing service to these customers during the Reconciliation Period.”9 • Entergy asked to postpone refunds or surcharges even though the utility estimated that it had over-recovered $243 million during the reconciliation period: “[Entergy] does not seek to implement a refund or surcharge of eligible fuel or purchased power costs at the conclusion of this case; rather, [Entergy] proposes to roll any ending fuel balances 7 SAR, Item 1 at 8. 8 SAR, Item 1 at 1 (“Reconciliation Period from July 1, 2009 to June 30, 2011”); see also AR, Item 244 (Order) FF 214. In the Order, findings of fact will be cited as “FF__” and conclusions of law will be cited as “CL __.” A copy of the Order is attached as Appendix B. 9 SAR, Item 1 at 8 (emphasis added). 4 forward to serve as the beginning balance for the next Reconciliation Period.”10 Thus, the Commission’s Order does not include refunds. 2. Because some electricity is lost as it travels over wires, the utility must perform a line-loss study to account for the total amount that must be generated to meet demand. To recover all of its fuel costs, a utility must account for line losses because not all the electricity generated reaches the utility’s customers; some is “lost” as electricity travels over wires from generation to consumption. The Commission’s Rule 25.237 explains that “[f]uel factors must account for system losses and for the difference in line losses corresponding to the voltage at which the electric service is provided.”11 Entergy did not use the line-loss study conducted during the reconciliation period to calculate actual fuel costs during that period; it used one thirteen years older. The utility conducted a line-loss study for the calendar year 2010—the middle of the 24-month reconciliation period of July 2009 through June 2011. 12 Thus, this study showed actual Fuel Reconciliation during the reconciliation period. But Entergy proposed to 10 Id. at 9 (emphasis added). 11 16 Tex. Admin. Code § 25.237(a)(1). 12 AR, Order at 9. 5 determine fuel expenses for retail customers using a line-loss study performed in 1997.13 C. Cities argued that the contemporaneous line-loss study would show actual fuel costs incurred during the reconciliation period, and that contemporaneous line-loss study showed that $4 million of fuel costs Entergy assigned to retail ratepayers were incurred to serve wholesale customers. Cities, parties in the rate case, argued that the fuel costs incurred during the reconciliation period should reflect the contemporaneous line-loss study.14 Cities calculated that, using the current line-loss study, retail customers paid nearly $4 million for fuel expenses that were not incurred to serve retail customers. Cities’ witness Nalepa testified: “[Entergy]’s own analysis demonstrates that adjusting the allocation of fuel costs over the reconciliation period to reflect the actual line losses for each voltage level for the reconciliation period results in retail customers subsidizing wholesale customers by approximately $3.98 million.”15 13 AR, Order at 9. 14 AR, Item 161 at 88–90 (Cities Initial Br.). 15 AR, Cities’ Ex. 6 at 44 ll.14–18. 6 D. The Commission decided that the contemporaneous line- loss study should be used. Although the ALJ proposed using the out-of-date 1997 line-loss study, the Commission used the contemporaneous 2010 line-loss study to determine fuel costs for service to retail customers during the reconciliation period.16 The Commission recognized that Entergy used the 2010 line-loss study to calculate the demand- and energy-related allocations the utility relied on for new base rates it asked the Commission to set. The Commission opined that those same, currently available line-loss factors should have been utilized in Entergy’s Fuel Reconciliation.17 The Commission found that using Entergy’s 2010 line-loss factors resulted in $3,981,271 less in actual fuel costs that Entergy incurred to serve retail customers during the reconciliation period. The Commission added the following two conclusions of law to the ALJ’s proposed conclusions: 19A. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding. 19B. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to include any issue related to the reasonableness of a utility’s fuel expenses and whether the utility has over- or under-recovered its reasonable fuel expenses. It is proper to use the new line-loss study to calculate Entergy’s fuel reconciliation and over-recovery. 16 AR, Order at 9. 17 AR, Order at 9. 7 Entergy claimed that the Commission’s Order was contrary to the Commission’s rules.18 E. Three Commission rules apply to a utility’s recovery of fuel expenses: Rule 25.235, Rule 25.236, and Rule 25.237. Three Commission rules address a utility’s recovery of fuel expenses: Rule 25.235 entitled “Fuel Costs — General,” Rule 25.236 entitled “Recovery of Fuel Costs,” and Rule 25.237, entitled “Fuel Factors.”19 Rule 25.235 explains the purpose for the system of allowing a utility to recover its fuel costs through a Fuel Factor with periodic reconciliations. Rule 25.236 explains that the Commission’s authority in a Fuel Reconciliation proceeding is broad. “The scope of the proceeding below allows consideration of ‘any issue related to determining the reasonableness of the electric utility’s fuel expenses during the reconciliation period.’” CenterPoint Energy Houston Elec., LLC v. Pub. Util. Comm’n, 212 S.W.3d 389, 399 (Tex. App.—Austin 2006, pet. granted, judgm’t vacated w.r.m.) (quoting 16 Tex. Admin. Code § 25.236(d)(2)). That same rule explains that the scope of a reconciliation proceeding 18 Id. 19 16 Tex. Admin. Code §§ 25.235–25.237. Copies are attached as Appendices E–G. 8 includes: “whether the electric utility has over- or under-recovered its reasonable fuel expenses.”20 Rule 25.237 recognizes that Fuel Factors “are temporary rates … .”21 The electric utility’s collection of revenues by Fuel Factors is subject to adjustments. “To the extent that there are variations between the fuel costs incurred and the revenues collected, it may be necessary or convenient to refund overcollections or surcharge undercollections.”22 F. The district court reversed the Commission’s decision about using the contemporaneous line-loss study. In the administrative appeal of Entergy’s rates, the district court affirmed the Commission on most issues, but it reversed on this one. The district court’s judgment states: Entergy’s Point of Error No. 1 addressing the use of a current line loss study rather that a prior-approved line loss study in allocating line loss costs among classes of customers establishes that the Commission erred in applying the current study in violation of Commission rules found at 16 TAC §25.236(e)(3) and 16 TAC 25.237(a) and (c)(2)(B). Accordingly, the Court FINDS that the PUC’s ruling was arbitrary and capricious and constitutes an error of Law. The Court REVERSES such ruling and REMANDS this matter to the Commission for further proceedings consistent with this Court’s Order.23 20 16 Tex. Admin. Code 25.236(d)(2). 21 16 Tex. Admin. Code § 25.237(a)(3). 22 16 Tex. Admin. Code § 25.237(a)(3)(B). 23 C.R. at 2118. 9 The Commission appeals the district court’s holding. Summary of the Argument None of the rules that were cited by the district court apply to the Fuel Reconciliation the Commission performed. Because Entergy did not ask the Commission to change its Fuel Factor, the two provisions of Rule 25.237 about setting a Fuel Factor do not apply. Because Entergy did not ask the Commission to award refunds, Rule 25.236(e)(3) about how to allocate refunds does not apply. Moreover, because Rule 25.236(e)(3) applies only to Entergy’s retail rate classes, it does not concern allocating fuel costs between retail and wholesale service. Thus, the district court erred to find that the Commission’s order violated those inapplicable rules. The Commission’s Order complies with the applicable rules. Rule 25.236(d) requires that the utility recover only reasonable and necessary fuel costs to serve retail customers. Thus, the Commission reasonably applied line-losses based on the line-loss study done contemporaneously with the reconciliation period. That showed that $4 million of the fuel costs Entergy wanted to recover were actually wholesale fuel costs that should not be imposed on retail customers. Moreover, Entergy has failed to show harm. It claims that it will be harmed if it is not allowed to allocate the $4 million to retail customers 10 based on the 1997 line-loss study but fails to show that it does not collect that $4 million from wholesale customers. Argument A. Standard of Review “The Commission’s interpretation of its own regulations is entitled to deference by the courts.” Pub. Util. Comm’n v. Gulf States Utils. Co., 809 S.W.2d 201, 207 (Tex. 1991). Courts “construe administrative rules, which have the same force as statutes, in the same manner as statutes. ” Rodriguez v. Serv. Lloyds Ins. Co., 997 S.W.2d 248, 254 (Tex. 1999) (citing Lewis v. Jacksonville Bldg. & Loan Ass’n, 540 S.W.2d 307, 310 (Tex. 1976).). Therefore, the courts look first to the plain language of the rule. “Unless the rule is ambiguous, we follow the rule’s clear language.” Rodriguez, 997 S.W.2d at 254 (citing RepublicBank Dallas, N.A. v. Interkal, Inc., 691 S.W.2d 605, 607 (Tex.1985)). But courts “defer to an agency’s interpretation of its own rules unless it is plainly erroneous or contradicts the text of the rule or underlying statute.” Sw. Pharmacy Solutions, Inc. v. Tex. Health & Human Servs., 408 S.W.3d 549, 558 (Tex. App.—Austin 2013, pet. denied) (citing Pub. Util. Comm’n v. Gulf States Utils. Co., 809 S.W.2d at 207); see also Tex. Bd. of Chiropractic Exam’rs v. 11 Tex. Med. Ass’n, 375 S.W.3d 464, 475 (Tex. App.—Austin 2012, pet. denied). B. The Commission’s Order complies with its rules. The Commission’s decision complies with its applicable rules. By their plain language, the rules cited in the district court’s judgment do not apply to this proceeding. Commission rules that do apply support the Commission’s order. 1. Rule 25.236(d) applies to this Fuel Reconciliation and authorizes the Commission’s decision. The applicable Commission rule requires the Commission to determine whether Entergy over- or under-recovered retail fuel costs. Rule 25.236(d)(2) states: “The scope of a fuel reconciliation proceeding includes any issue related to determining the reasonableness of the electric utility’s fuel expenses during the reconciliation period and whether the electric utility has over- or under-recovered its reasonable fuel expenses.”24 Because Entergy was reconciling fuel costs and revenues that affect only its retail customers,25 the question is whether Entergy “over-or under- recovered its reasonable fuel expenses”26 incurred to serve retail customers. 24 16 Tex. Admin. Code § 25.236(d)(2). 25 SAR, Item 1 at 8. 26 16 Tex. Admin. Code § 25.236(d)(2). 12 The plain language of Rule 25.236(d)(1)(A) also shows that only retail fuel expenses should be considered. The rule limits the Fuel Reconciliation to expenses incurred to service retail customers stating: “In a proceeding to reconcile fuel factor revenues and expenses, an electric utility has the burden of showing that: (A) its eligible fuel expenses during the reconciliation period were reasonable and necessary expenses incurred to provide reliable electric service to retail customers.”27 By using the contemporaneous line-loss study, the Commission followed those rules; it limited eligible fuel expenses to those incurred to serve retail customers. Entergy, by using the out-of-date line-loss study, allocated to retail customers nearly $4 million of fuel expenses that were actually incurred to provide electricity to wholesale customers. The $4 million was spent for fuel expenses Entergy incurred to generate electricity that was lost transmitting electricity to wholesale customers. Fuel expenses to serve wholesale customers are not “reasonable and necessary expenses incurred to provide reliable electric service to retail customers.”28 Thus, the Commission complied with its applicable rules by refusing to include those wholesale fuel costs in the reconciliation. 27 16 Tex. Admin. Code § 25.236(d)(1)(A) (emphasis added). 28 Id. 13 2. None of the rules cited by the district court apply to the Fuel Reconciliation in this case. None of the rules cited by the district court apply to the Fuel Reconciliation in this case. The district court’s judgment cited Rules 25.236(e)(3), 25.237(a), and 25.237(c)(B). By their plain language, the two cited sections of Rule 25.237 apply to setting Fuel Factors—temporary fuel rates—not to a Fuel Reconciliation where the Commission determines the actual, final fuel rates. Because the Commission reconciled Entergy’s fuel expenses but did not set a new Fuel Factor, Rule 25.237 cannot apply. The cited provision in Rule 25.236 applies to “interclass allocations” of refunds or surcharges in a Fuel Reconciliation. For two reasons, the plain language of that rule does not apply. First, it addresses refunds and surcharges, but Entergy specifically asked not to implement a refund or surcharge in this case, but to postpone it to a later docket.29 Second, “interclass allocations” refers to the retail rate classes for which the Commission is determining an over- or under-recovery of fuel costs. Because none of them are wholesale rate classes, the rule, by its plain language, does not apply to a decision that $4 million was incurred for service to wholesale rather than retail ratepayers. 29 SAR, Item 1, at 9. 14 a. Rule 25.236(e)(3) does not apply to this Fuel Reconciliation. Rule 25.236(e)(3) refers to “[i]nterclass allocations of refunds and surcharges … .”30 But Entergy specifically asked to postpone refunding the over-collected fuel expenses to a subsequent proceeding;31 there were no refunds or surcharges in this proceeding. Thus, the plain language of Rule 25.236(e)(3) does not apply to this case. In addition, the term “interclass allocations” in the rule applies to the classes of customers included in Fuel-Factor rates that the Commission set. Because the Commission does not set rates for Entergy’s wholesale customers, the rule, by its plain language, does not apply to Entergy’s wholesale customers. Thus, the Rule in no way prevents the Commission from deciding that the contemporaneous line-loss study should be used to decide whether the fuel costs were incurred for retail customers or for wholesale customers. For this separate reason, the plain language of the rule makes it inapplicable to this proceeding. The district court erred by finding that the Commission violated this rule when it decided the Fuel Reconciliation in this case. 30 Tex. Admin. Code § 25.236(e)(3) (emphasis added). 31 SAR, Item 1 at 9; AR, Item 185 at 320. 15 b. Rule 25.237(a) does not apply to a Fuel Reconciliation. Rule 25.237(a) does not apply to this case because it addresses only Fuel Factors. By its plain language, it does not apply to this Fuel Reconciliation. A Fuel Factor is the forward-looking estimated rate; the reconciliation sets the actual rate. The reference to line losses in Rule 25.237(a) says nothing about how to determine line losses in a Fuel Reconciliation. By requiring a Fuel Factor to “account for system losses and for the difference in fuel reconciliation corresponding to the voltage at which the electric service is provided,” Rule 25.237(a)(1) merely recognizes the importance of a line-loss study to determine whether a utility has over- or under-recovered its fuel expenses. The district court erred to find that the Commission violated this rule about Fuel Factors when it decided the Fuel Reconciliation in this case. c. Rule 25.237(c)(2)(B) does not apply to a Fuel Reconciliation. Rule 25.237(c)(2)(B) also applies only to Fuel Factors, not Fuel Reconciliations. Thus, by its plain language, the rule does not apply to this Fuel Reconciliation. Similar to the rule above, the reference to line losses in Rule 25.237(c)(2)(B) says nothing about how to determine line losses in a Fuel Reconciliation. To the extent that this Fuel-Factor rule mentions a line-loss 16 study, it shows how important a line loss is to determine the amount of fuel expenses. The rule states that “the proposed fuel factors utilize a commission-approved adjustment to account for line losses corresponding to the voltage at which the electric service is provided.”32 The district court erred to find that the Commission violated this Fuel- Factor rule when it decided the Fuel Reconciliation in this case. Thus, the Commission cannot have violated Rules 25.236(e)(3), 25.237(a), and 25.237(c)(B) because, by their plain language, they do not apply to this case. And the Commission complied with Rule 25.236(d), which does apply. That rule explains that “[t]he scope of a fuel reconciliation proceeding includes any issue related to determining the reasonableness of the electric utility’s fuel expenses during the reconciliation period and whether the electric utility has over- or under- recovered its reasonable fuel expenses.”33 The Commission’s Order complied with the applicable rule; it allowed Entergy to collect only for the fuel expenses actually incurred to serve retail customers. The Commission reasonably interpreted its rules, and that interpretation should be affirmed by the Court. 32 16 Tex. Admin. Code § 25.237(c)(2)(B). 33 16 Tex. Admin. Code § 25.236(d)(2). 17 C. Entergy has not shown prejudice to its substantial rights. The district court also erred in reversing the Commission’s fuel- reconciliation decision because Entergy made no showing that the Commission’s decision will harm Entergy, and showing prejudice to substantial rights is a requirement for a plaintiff to prevail in a suit for judicial review of an agency’s order. Tex. Gov’t Code § 2001.174(2) (directing the court to “reverse or remand the case for further proceedings if substantial rights of the appellant have been prejudiced” for stated reasons) (emphasis added); El Paso Elec. Co. v. Pub. Util. Comm’n, 917 S.W.2d 846, 857 n.6 (Tex. App.—Austin 1995, writ dism’d by agr.)(“We need not address the merits of the City’s argument for two reasons: (1) the City has not demonstrated that its substantial rights in this case have been prejudiced by the alleged superfluous findings, a prerequisite for reversal or remand under APA …”). Entergy asked the Commission to address only retail rates. Wholesale rates for Entergy, which serves an area outside the Texas intrastate electric grid called ERCOT, are usually set by the Federal Energy Regulatory 18 Commission.34 In addition, Rule 25.236(d)(1)(A) specifically speaks to retail rates. 16 Tex. Admin. Code § 25.236(d)(1)(A). Entergy failed to show harm because, although Entergy claims harm based on treating wholesale fuel expenses differently than retail fuel expenses, the utility refused to give any information about recovering fuel expenses from wholesale customers. An Entergy witness maintained that costs would be stranded if the contemporaneous line-loss study were used for retail customers while maintaining that wholesale rates were irrelevant. (See AR, Tr. 1466-75, (“[I]f you are retrospectively changing an allocation factor, then, to me, no, you’re stranding those costs.” at 1470–71) (“[H]ow a contract is written and that contract that’s entered into between ETEC or any wholesale customer and the company again is totally separate and distinct from a cost of service used to set retail rates for [Entergy] in the state of Texas.” at 1466).) The Commission has evidence only about Entergy’s retail fuel expenses. Based on that evidence, in addition to the $243 million of fuel expenses that the utility estimated that it over- recovered from retail customers, Entergy also recovered almost $4 million 34 See Gulf States Utils. Co. v. Pub. Util. Comm’n, 841 S.W.2d 459, 471 (Tex. App.—Austin 1992, writ denied) (“FERC’s jurisdiction encompasses wholesale rates and power allocations affecting those rates, as well as purchaser-prudence issues arising in the context of integrated pooling agreements or sales between corporate affiliates.”). 19 for fuel costs that should have been allocated to wholesale rather than retail customers. Entergy failed to show that the Commission’s decision to use the contemporaneous line-loss study would cause it harm. Conclusion The district court erred; it based its holding that the Commission’s Order was arbitrary and capricious on rules that do not apply to this fuel- reconciliation. And the Commission’s Order accords with the applicable fuel-reconciliation rules. Prayer The Commission asks the Court to reverse the district court’s judgment to the extent that it found error in the Commission’s order (that the Commission erred in applying the current line-loss study) and to affirm the Commission’s order. The Commission asks the Court for such other relief as it may be entitled. Respectfully submitted, KEN PAXTON Attorney General of Texas CHARLES E. ROY First Assistant Attorney General 20 JAMES E. DAVIS Deputy Attorney General for Civil Litigation JON NIERMANN Division Chief Environmental Protection Division /s/ Elizabeth R. B. Sterling Elizabeth R. B. Sterling Assistant Attorney General Texas State Bar No. 19171100 elizabeth.sterling@texasattorneygeneral .gov Environmental Protection Division Office of the Attorney General P.O. Box 12548, MC-066 Austin, Texas 78711-2548 512.463.2012 512.457.4616 (fax) COUNSEL FOR PUBLIC UTILITY COMMISSION OF TEXAS Certificate of Compliance I certify that the foregoing computer-generated document has 4254 words, calculated using the computer program WordPerfect 12, pursuant to Texas Rule of Appellate Procedure 9.4. /s/ Elizabeth R. B. Sterling Elizabeth R. B. Sterling 21 Certificate of Service I hereby certify that on this the 31st day of March 2015, a true and correct copy of the foregoing document was served on the following counsel electronically, through an electronic filing service and by email: /s/ Elizabeth R. B. Sterling Elizabeth R. B. Sterling Counsel for Appellant Entergy Texas, Inc.: Marnie A. McCormick Patrick J. Pearsall Duggins, Wren, Mann & Romero, LLP P. O. Box 1149 Austin, Texas 78767-1149 512.744.9300 512.744.9399 (fax) mmccormick@dwmrlaw.com ppearsall@dwmrlaw.com Counsel for Appellants Cities of Anahuac, et al.: Daniel J. Lawton The Lawton Law Firm, P.C. 12600 Hill Country Blvd, Ste. R-275 Austin, TX 78738 512.322.0019 855.298.7978 (fax) dlawton@ecpi.com 22 Counsel for Appellant Office of Public Utility Counsel: Sara J. Ferris Senior Assistant Public Counsel Office of Public Utility P.O. Box 12397 Austin, Texas 78711-2397 512.936.7500 512.936.7520 (fax) sara.ferris@opuc.texas.gov Counsel for State Agencies: Katherine H. Farrell Assistant Attorney General Administrative Law Division Energy Rates Section Office of the Attorney General P.O. Box 12548, MC 018-12 Austin, Texas 78711-2548 512.475.4237 512.320.0167 (fax) katherine.farrell@texasattorneygeneral.gov Counsel for Texas Industrial Energy Consumers: Rex VanMiddlesworth Benjamin Hallmark Thompson & Knight LLP 98 San Jacinto Blvd., Ste. 1900 Austin, Texas 78701 512.469.6100 512.469.6180 (fax) rex.vanm@tklaw.com benjamin.hallmark@tklaw.com 23 APPENDIX A District Court Judgment CC l! Kl4~51'G U2 F'Ued In 'l'h , . of Travis ~ 011mct Cow·: oumy, 't!ixa£ EM OCT 1~ 2ui41 CAUSE NO. D-J-GN-lJ-000121 At (/ .J.if A Amalia Rodrigu&z·Mend- . M oza; Glerh ENTERGY TEXAS, 1INC., § IN THE DISTRICT COURT OF Pliaintiiff § § 'V. § TRAVIS COUNTY, TEXAS § PU[JLIC UTILITY COMMISSION, § Defendant § 353Ro JUDICIAL DISTRICT ORDER ON ADMINISTRATIVE APPEAL On July 22, 2014, the Court heard Plaintiffs appeal from Defendant's Order in PUC Docket No. 39896, SOAH Docket No. . The administrative record was admitted into evidence, and the Court lhe.ard oral argument. Entergy, the Cities, and OPUC each asserted points of error challenging the Commission's order. Having considered the pleadings, the evidence and the arguments of counsel, the Court makes the following rulings: l. Entergy' s Point of Error No. I arity to Defer Expenses Related to its Proposed Transition to Membership in the Midwest Independent System Operator, Docket No. 39741 (pending) into this proceeding. Although it did not agree, Staff did not oppose the consolidation. 11. On January l3, 2012, the AUs issued SOAH Order No. 4 granting the motions for admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and participate as counsel for Kroger and the motion for admission pro hac vice filed by Rick D. Chamberlain to appear and panicipate as counsel for Wal-Mart. 000000011 PUC Docket No. 398% Order Page 12 of 43 SOAH Docket N o . - 12. On January 19, 20 12, the Commission issued a supplemental preliminary order identifying two additional issues to be addressed in this case and concluding that the company's proposed purchased-power capacity rider should not be addressed in this case and that such costs should be recovered through base rates. 13. ETI timely filed with the Conunission petitions for review of the rate ordinances of the municipalities e)(ercising original jurisdiction within its service territory. All such appeals were consolidated for determination in this proceeding. 14. On April 4, 2012, the AUs issued SOAH Order No. 13 severing rate case expense issues into Application of Entergy Texas, Inc. for Rate Case Expenses Severed f rom PUC Docket No. 39896, Docket No. 40295 (pending). 15. On April 13, 2012, ETI adjusted its request for a proposed increase in annual base rate revenues to approximately $104.8 million over adjusted test-year revenues. 16. The hearing on the merits commenced on April 24 and concluded on May 4, 2012. 17. Initial post-hearing briefs were filed on May 18 and reply briefs were filed on May 30, 2012. l7A. On August 7, 2012, the SOAH ALls filed a letter with the Commission recommending changes to the PFD. 17B At the July 27, 2012 open meeting, ETI agreed to extend the effective date of rates to August 31, 2012 to provide the Commission sufficient time to c.onsider the issues in this proceeding. l7C. The Commission considered the proposal for decision at the August 17, 2012 and August JO. 2012 open meetings. l 70 . At the August 30, 20 l 2 open meeting, ETI agreed to ex.tend the effective date of rates to September 14, 20 l 2. l 7E. At the August 17. 2012 open meeting, parties announced on the record a settlement of the amount of costs for the trnnsition to MISO. 000000012 PUC Docket No. 39896 Order Page 13 of43 SOAH Docket N o . - Rate Base 18. Capital additions that were closed to ETI' s plant-in-service between July 1, 2009 and June 30, 2011. are used and useful in providing service to the public and were prudently incurred. 19. ETI's proposed Hurricane Rita regulatory asset was an issue re.c;olved by the black-box settlement in Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010). 20. Accrual of carrying charges on the Hurricane Rita regulatory asset should have ceased when Docket No. 37744 concluded because the asset would have then begun earning a rate of return as part of rate base. 21. The appropriate calculation of the Hurricane Rita regulatory asset should begin with the amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the test-year in the present case, and less the amount of additional insurance proceeds received by ETI after the conclusion of Docket No. 37744. 22. A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should remain in rate base, applying a five-year amonization rate beginning August 15, 2010. 23. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance reserve. 24. The company requested in rate base its prepaid pension assets balance of $55,973,545, which represents the accumulated difference between the Statement of Financial Accounting Standards (SfAS) No. 87 calculated pension costs each year and the actual contributions made by the company to the pension fund. 25. The prepaid pension assets balance includes $25,311 ,236 capitalized to construction work in progress (CWIP). 26. It is not necessary to the financial integrity of ETI to include CWTP in rate base, and there was insufficient evidence showing that major projects under construction were efficiently and prudently managed. 000000013 PUC Docket No. 39896 Order Page 14 of 43 SOAH Docket N o . - 27. The portion of the prepaid pension assets balance that is capitalized to CWIP should not be included in ETl's rate base. 28. The remainder of the prepaid pension assets balance should be included in ETr s rate base. 28A. When items are excluded from rate base, the related ADFIT should also be excluded. The amount of ADFIT associated with the $25 million capitalized to CWIP and excluded from rate base is $8,858,913. The adjusted ADFIT for the prepaid pension asset remaining in Entergy's rate base should be reduced by $8,858,933. 29. ETI should be permitted to accrue an allowance for funds used during constmction on the portion of ETI's Prepaid Pension Assets Balance capitalized to CWIP. 30. The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48 (FIN 48), "Accounting for Uncertainty in Income Taxes," requires ETI to identify each of its uncertain tax positions by evaluating the taK position on its technical merits to determine whether the position, and the corresponding deduction, is more-likely-than-not to be sustained by the Internal Revenue Service (IRS) if audited. 3 l. FIN 48 requires ETI to remove the amount of its uncenain tax positions from its Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting purposes and record it as a potential liability with interest to better reflect the company's financial condition. 32. At test-year-end, ETI had $5,916,461 in FIN 48 liabilities, meaning ETI ha.s, thus far, avoided paying to the IRS $5,916,461 in tax dollars (the FIN 48 liability) in reliance upon tax positions that the company believes will not prevail in the event the positions are challenged, via an audit, by lhe IRS. 33. ETl has deposited $1,294,683 with the lRS in connection with the FlN 48 liability. 34. The IRS may never audit ETI as to its uncertain tax positions creating the FIN 48 liability. 35. Even if ETI is audited, ETI might prevail on its uncertain tax positions. 36. ETI may never have to pay the IRS the FIN 48 liability. 000000014 PUC Docket No. 39896 Order Pnge 15 of43 SOAH Docket N o . - 37. Other than the amount of its deposit with the IRS. ETI has current use of the FIN 48 liability funds. 38. Until actually paid to the IRS , the FIN 48 liability represents cost-free capital and should be deducted from rate base. 39. The amount of $4,621,778 (representing ETI's full FIN 48 liability of $5,916,461 less the $1 ,294,683 cash deposit ETI has made with the lRS for the FIN 48 liability) should be added to ETI's ADFIT and thus be used to reduce ETl's rate base. 40. ETr s application and proposed tariffs do not indude a request for a tracking mechanism or rider to collect a return on the FIN 48 liability. 40A. It is appropriate for ETI to create a deferred-tax-account tracker in the form of a rider to recover on a prospective basis an after~tax return of 8.27 % on the amounts paid to the IRS that result from an unfavorable FIN 48 audit. The rider will track unfavorable FIN 48 rulings and the return will be applied prospectively to FIN 48 amounts disallowed by an IRS audit after such amounts are actually paid to the federal government. If ETI prevails in an appeal of a FIN 48 decision, then any amounts collected under the rider related to that decision should be credited back to ratepayers. 4 t. Deleted. 42. [nvestor-owned electric utilities may include a reasonable allowance for cash working capital in rate base as determined by a lead-lag study conducted in accordance with the Commission's rules. 43. Cash working capital represents the 3mount of working capital, not specifically oddressed in other rate base items, that is necessary to fund the gap between the time expenditures are made and the time corresponding revenues are received. 44. The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted for known and measurable changes, and is consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii). 000000015 PUC Docket No. 39896 Order Page 16 0143 SOAH Docket No.- 45. It is reasonable to establish ETl's cash working capital requirement based on ETI's lead- lag study as updated in lay Joyce's rebuttal testimony and on the cost of service approved for ETI in this case. 46. As a result of the black-box settlements in Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Nov. 7, 2008) and Docket No. 37744. the Commission did not approve ETI's storm damage expenses since 1996 and its storm damage reserve balance. 47. ETI established a prima focie case concerning the prudence of its stonn damage expenses incurred since 1996. 48. Adjustments to the storm damage reserve balance proposed by intervenors should be denied. 49. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance reserve. 50. ETI's appropriate Test-Year-end stonn reserve balance was negative $59,799,744. 51. The amount of $9,846,037, representing the value of the average coal inventory maintained at ETl's coal-burning facilities, is reasonable, necessary, and should be included in rate base. 52. The Spindletop gas storage facility (Spindletop facility) is used and useful in providing reliable and flexible natural gas supplies to ETI' s Sabine Station and Lewis Creek generating plants. 53. The Spindletop facility is critical to the economic, reliable operation of the Sabine Station and Lewis Creek generating plants due to their geographic location in the for western region of the Entergy system. 54. It is reasonable and appropriate to include ETI's share of the costs to operate the Spindletop facility in rate base. 55. Staff recommended updating ETI's balance amounts for short-tenn assets to the 13- month period ending December 2011, which was the most recent information available. 000000016 PUC Docket No. 391196 Order Page 17 of4J SOAH Docket No. Staffs proposed adjustments should be incorporated into the calculation of ETI' s rate base. 56. The following short-term asset amounts should be included in rate base: prepayments at $8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485. 57. The amount of $1,127,778, representing costs incurred by ETI when it acquired the Spindletop facility, represent actual costs incurred to process and close the acquisition. not mere mark-up costs. 58. ETI' s $ I.127,778 in capitalized acquisition costs should be included in rate base because ETI incurred these costs in conjunction with the purchase of a viable asset that benefits its retail customers. 59. In its application, ETI capitalized into plant in service accounts some of the incentive payments ETI made to its employees. ETI seeks to include those amounts in rate base. 60. A portion of those capitalized incentive accounts represent payme.nts made by ETI for incentive compensation tied to financial goals. 61. The portion of ETl' s incentive payments that are capiralized and that are financially- based should be excluded from ETI' s race base because the benefits of such payments inure most immediately and predominantly to ETI's shareholders, rather than its electric customers. ETI's capitalized incentive compensation that is financially based is $335,752.96 and should be removed for rate base. 62. The test-year for ETI's prior ratemaking proceeding ended on June 30, 2009, and the reasonableness of ETI's capital costs (including capitalized incentive compensation) for that prior period was dealt with by the Commission in that proceeding and is not at issue in this proceeding. 63. In this proceeding, ETI's capitalized incentive compensation that is financially-hased should be excluded from rate base, but only for incentive costs that ETI capitalized during the period from July 1, 2009 (the end of the prior test-year) through June 30, 2010 (the commencement of the current test~ year). 000000017 PUC Docket No. 39896 Order Page 18 or43 SOAH Docket N o . - Rate o(Retur11 and Cost of Capital 64. A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable opportunity to earn a reasonable return on its invested capital. 65. The results of the discounted cash flow model and risk premium approach support a ROE of 9 .80 percent. 65A. It is not appropriate to add 15 points to the ROE due to unsettled economic conditions facing utilities. 66. A 9.80 percent ROE is consistent with ETI's business and regulatory risk. 67. ETI's proposed.6.74 percent embedded cost of debt is reasonable. 68. The appropriate capital structure for ETI is 50.08 percent long-term debt and 49.92 percent common equity. 69. A capital structure composed of 50.08 percent debt and 49.92 percent equity is reasonable in light of ETI's business and regulatory risks . 70. A capital structure composed of 50.08 percent debt and 49.92 percent equity will help ETI attract capital from investors. 71. ETI's overall rate of return should be set as follows: CAPITAL WEIGHTED AVG COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL LONG· TER!'1 DEBT 50.08% 6.74% 3.38% COMMON EQUITY 49.92% 9.80% 4.89% TOTAL 100.00% 8.27% Ooera#ng Expenses 72. ETI's test-year purchased capacity expenses were $245,965,886. 73. ETI requested an upward adjustment of $30,809,355 as a post-test-year adjustment to its purchased capacity costs. This request was based on ETI's projections of its purchased capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the rate-year). 000000018 PUC Docket No. J9896 Order Page 19 or43 SOAH Docket No.- 74. ETI's purchased capacity expense projections were based on estimates of rate-year expenses for: (a) reserve equalization payments under Schedule MSS- 1; (b) payments under third-party capacity contracts; and (c) payments under affiliate contracts. 75. ETI's projection of its rate-year reserve equalization payments under Schedule MSS-1 is based on numerous assumptions, including load growths for ETI and its affiliates. future capacity contracts for ETI and its affiliates, and future values of the generation assets of ETl and its affiliates. 76. There is substantial uncertainty with regard to ETI's projection of its rate-year reserve equalization payments under Schedule MSS-1 . 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 tmder the contract, even though that assumption is inconsistent with ETI's historical experience. 78. There is substantial uncenainty with regard to ETI's projection of its rate-year third-party capacity-contract payments. 79. ETI's estimates of its rate-year purchases under affiliate contracts are based on a mathematical formula set out in Schedule MSS-4. 80. The MSS-4 formula for rate-year affiliate capacity payments reflects that these payments will be based on ratios and costs that cannot be determined until the month that the payments are to be made. 81. Over $11 million of ETI' s affiliate transactions were based on a 2013 contract (the EA[ WBL Contract) that was not signed until April 11, 2012. 82. There is uncenainty about whether the EAI WBL Contract will ever go into effect. 83. ETI projects purchasing over JOO megawatts (MW) more in purchased capacity in the rate-year than it purchased in the test-year. 84. ETI experienced substantial load growth in the two years before the test· year. and it continues to project similar load growth in the future. 000000019 PUC Docket No. 39896 Order Page 20 or4J SOAH Docket N o . - 85. ETI did not meet its burden of proof to demonstrate that a known and measurable adjustment of $30,809,355 should be made to its test-year purchased capacity expenses. 86. ETI's purchased capacity expense in this case should be based on the test-year level of $245,965,886. 87. ETI incurred $1 ,753,797 of transmission equalization expense during the test-year. 88. ETI proposed an upward adjustment of $8,942,785 for its transmission equalization expense. This request was based on ETI's projections of its transmission equalization expenses during the rate-year. 89. The transmission equalization expense that ETI will pay in the rate-year will depend on future costs and loads for each of the Entergy operating companies. 90. ETl's projection of its rate-year transmission equalization expenses is uncertain and speculative because it depends on a number of variables, including future transmission investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating expenses, and loads of each of the Entergy operating companies. 91. ETI seeks increased transmission equalization expenses for transmission projects that are not currently used and useful in providing electric service. ETI's post-test-year adjustment is based on the assumption that certain planned transmission projects will go into service after the test-year. At the close of the hearing. none of the planned transmission projects had been fully completed and some were still in the planning phase. 92. It is not reasonable for ETI to charge its retail ratepayers for transmission equalization expenses related to projects that are not yet in-service. 93. ETI's request for a post-test-year adjustment of $8,942,785 for rate-year transmission equalization expenses should be denied because those expenses are not known and measurable. ETI's post-test-year adjustment does not with reasonable certainty reflect what ETI's transmission equalization expense will be when rates are in effect. 94 . ETI's transmission equalization expense in this case should be based on the test-year level of $1,753,797. 000000020 PUC Docket No. 39896 Order Page 21 of 43 SOAH Docket N o - 95. P.U.C. SUBST. R. 25.23 l(c)(2)(ii) states that the reserve for depreciation is the accumulation of recognized allocations of original cost. representing the recovery of initial investment over the estimated useful life of the asset. 96. Except in the case of the amonization of the general plant deficiency, the use of the remaining life depreciation method to recover differences between theoretical and actual depreciation reserves is the most appropriate method and should be continued. 97. It is reasonable for ETI to calculate depreciation reserve allocations on a straight-line basis over the remaining. expected useful life of the item or facility. 98. Except as described below, the service lives and net salvage rates proposed by the company are reasonable. and these service lives and net salvage rates should be used in calculating depreciation rates for the company's production, transmission. distribution, and general plant assets. 99. A 60-year life for Sabine Units 4 and 5 is reasonable for purposes of establishing production plant depreciation rates. 100. The retirement (actuarial) rate method, rather than the interim retirement method, should be used in the development of production plant depreciation rates. 10 t. Production plant net salvage is reasonably based on the negative five percent net salvage in existing rates. 102. The net salvage rate of negative 10 percent for ETI's transmission structures and improvements (FERC Account 352) is the most reasonable of those proposed and should be adopted. 103. The net salvage rate of negative 20 percent for ETI's transmission station equipment (FERC Account 353) is the most reasonable of those proposed and should be adopted. 104. The net salvage rate of negative five percent for ETr s transmission towers and fixtures (FERC Account 354) is the most reasonable of those proposed. and should be adopted. 105. The net salvage rate of negative 30 percent for ETI's transmission poles and fixtures (FERC Account 355) is the most reasonable of those proposed and should be adopted. 000000021 PUC Docket No. 39896 Order Page 22 or43 SOAH Docket No. 106. The net salvage rate of negative 30 percent for ETI's transmission overhead conductors and devices (FERC Account 356) is the most reasonable of those proposed and should be adopted. 107. A service life of 65 years and a dispersion curve of R3 for ETI' s distribution structures and improvements (FERC Account 361) are Lhe most reasonable of those proposed and should be approved. 108. A service life of 40 years and a dispersion curve of Rl for ETI's distribution poles, towers, and fixtures (FERC Account 364) are the most reasonable of those proposed and should be approved. 109. A service life of 39 years and a dispersion curve of R0.5 for ETrs distribution overhead conductors and devices (FERC Account 365) are the most reasonable of those proposed and should be approved. 110. A service life of 35 years and a dispersion curve of Rl.5 for ETI' s distribution underground conductors and devices (FERC Account 367) are the most reasonable of those proposed and should be approved. 111. A service life of 33 years and a dispersion curve of L0.5 for ETI's distribution line transformers (FERC Account 368) are the most reasonable of those proposed and should be approved. 112. A service life of 26 years and a dispersion curve of L4 for ETI's distribution overhead service (FERC Account 369.1) are the most reasonable of those proposed and should be approved. l l3 . The net salvage rate of negative five percent for ETI's distribution structures and improvements (FERC Account 361) is the most reasonable of those proposed and should be adopted. 114. The net salvage rate of negative 10 percent for ETI's distribution station equipment (FERC Account 362) is the most reasonable of those proposed and should be adopted. 000000022 PUC Docket No. 39896 Order Page 2.1 of43 SOAH Docket N o - - - 115. The net salvage rate of negative seven percent for ETI's distribution overhead conductors and devices (FERC Account 365) is the most reasonable of those proposed and should be adopted. 116. The net sal,vage rate of positive five. percent for ETI's distribution line transformers (FERC Account 368) is the most reasonable of those proposed and should be adopted. 117. The net salvage rate of negative lO percent for ETl's distribution overhead services (FERC Account 369. l) is the most reasonable of those proposed and should be adopted. 118. The net salvage rate of negative LO percent for ETl's distribution underground services (FERC Account 369.2) is the most reasonable of those proposed and should be adopted. 119. A service life of 45 years and a dispersion curve of R2 for ETJ' s general structures and improvements (FERC Account 390) are the most reasonable of those proposed and should be approved. 120. The net salvage rate of negative 10 percent for ETl's general structures and improvements (FERC Account 390) is the most reasom1ble of those proposed and should be adopted. 121. lt is reasonable to conven the $21.3 million deficit that has developed over time in the reserve for general plant accounts to General Plant Amortization. 122. A ten-year amortization of the deficit in the reserve for general plant accounts is reasonable and should be adopted. 123. FERC pronouncement AR-15 requires amortization over the same life as recommended based on standard life analysis. A standard lif'e analysis determined that a five-year life was appropriate for general plant computer equipment (FERC Account 391.2). Therefore, a five year amortization for this account is reasonable and should be adopted. 124. ETI proposed adjustments to its test-year payroll costs to reflect: (a) changes to employee headcount levels at ETI and Entergy Services. Inc. (ESI); and (b) approved wage increases set to go into effect after the end of the test-year. 125. The proposed payroll adjustments are reasonable but should be updated to reflect the most recent available information on headcount levels as proposed by Commission Staff. 000000023 PUC Docket No. 39896 Order Page 2.a of 43 SOAH Docket No.- ln addition to adjusting payroll expense levels, the more recent headcount numbers should be used to adjust the level of payroll tax expense, benefits expense, and savings plan expense. 126. Staff has appropriately updated headcount levels to the most recent available data but errors made by Staff should be corrected. The corrections related to: (a) a double cowiting of three ETI and one ESI employee; (h) inadvertent use of the ETI benefits cost percentage in the calculation of ESI benefits costs; (c) an inappropriate reduction of savings plan costs when such costs were already included in the benefits percentage adjustments; and (d) corrections for full-time equivalents calculations. Staffs ETI headcount adjustment (AG-7) overstated operation and maintenance (O&M) pa.yroll reduction by $224,217. and ESI headcount adjustment (AG-7) understated O&M payroll increase by $37,531. 127. ETI included $14,187,744 for incentive compensation expenses in its cost of service. 128. The compensation packages that ETI offers its employees include a base payroll amount. armual incentive programs, and long-term incentive programs. The majority of the compensation is for operational measures, but some is for financial measures. 129. Incentive compensation that is based on financial measures is of more immediate and predominant benefit to shareholders, whereas incentive compensation based on operational measures is of more immediate and predominnnt benefit to ratepayers. 130. Incentives to achieve operational measures are necessary and reasonable to provide utility services but those to achieve financial measures are not. 131. The $5,376,975 that was paid for long term incentive programs was tied to financial measures and. therefore. should not be included in ETI's cost of service. 132. Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062 was tied to financial measures and, therefore. should be disallowed. 133. In total, the amount of incentive compensation that should be disallowed is $6,196,037 because it was related to financial measures that are not reasonable and necessary for the provision of electric service. An additional reduction should be made to account for the 000000024 PUC Docket No. 39896 Order Page 25 or 43 SOAH Docket No. FICA taxes ETI woul 25.2% $0.03834 $0.04799 1000) OPC criticized ETI’s declining block rate structure as being contrary to energy efficiency efforts. OPC witness Benedict noted that under ETI’s proposed rate structure, once kWh usage exceeds 1,000 in a winter month, the per-kWh cost of consumption falls by 34 percent. Thus, because a declining block rate structure lowers the per-unit rate for high levels of consumption, heavy users are induced to consume more than they would otherwise. In his view, this runs contrary to the Legislature’s goal of reducing both energy demand and energy consumption in Texas, as stated in PURA § 39.905: (a) It is the goal of the legislature that: . . . (2) all customers, in all customer classes, will have a choice of and access to energy efficiency alternatives and other choices from the market that allow each customer to reduce energy consumption, summer and winter peak, or energy costs. Therefore, Mr. Benedict recommended that the declining block rate be phased out over time. He stated this would ease the transition to a rate structure without a declining block, and it would allow time for customers to switch to more efficient heating systems. Mr. Benedict proposed that the phase-out take place over three rate cases, beginning with a one-third reduction in the block differential proposed by ETI in this case. Reducing ETI’s proposed block differential from 2.469ȼ 1024 OPC Ex. 6 (Benedict Direct) at 42. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 317 PUC DOCKET NO. 39896 to 1.645ȼ accomplishes the initial one-third reduction, as illustrated below (using ETI’s requested revenue requirement):1025 Reduced ETI ETI Percent Block Rate Percent Rate Element Current Proposed Increase Differential Increase Customer Charge (per month) $5.00 $6.00 20.0% $6.00 20% Energy Charge (Summer, all 25.3% 23.1% $0.05802 $0.07268 $0.07141 kWh) Energy Charge (Winter, kWh ≤ 25.3% 23.1% $0.05802 $0.07268 $0.07141 1000) Energy Charge (Winter, kWh > 25.2% 43.3% $0.03834 $0.04799 $0.05496 1000) Mr. Benedict stated that his proposal related to an intra-class rate design issue and was not intended to affect the amount of revenue to be collected from the residential class or any other class. If, however, the Commission approves a different revenue requirement for the residential class to reflect various proposed adjustments, rates for the class will need to be recomputed regarding a reduced block differential1026 Staff generally agreed with OPC’s recommendation for a reduction in the rate differential between the residential winter kWh ≤ 1000 block and the winter kWh > 1000 block, due to the inconsistency between the incentives produced under declining block rates and the State’s energy efficiency goals. Staff witness Abbott stated that the extreme cold weather event of February 2011 demonstrated a need to incentivize wintertime energy efficiency measures, or at least a need to avoid encouraging excess energy usage. Therefore, Mr. Abbott agreed that some reduction in the rate block differential is warranted to better encourage wintertime energy conservation at the margin.1027 ETI witness Talkington testified that the RS rates are cost-based with a declining block rate in winter. According to Ms. Talkington, residential load factors in winter increase as energy usage increases, and there is also a decrease in the fixed unit cost ($/kWh) as energy usage increases. She 1025 OPC Ex. 6 (Benedict Direct) at 43-45. 1026 OPC Ex. 6 (Benedict Direct) at 46. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 318 PUC DOCKET NO. 39896 provided analysis to support her position.1028 Ms. Talkington explained that residential rates do not include demand charges because of the absence of residential demand meters. However, residential energy rates can be structured the same as the non-residential classes; that is, customer charge, demand charge and energy charge. She developed residential rates on this basis to show that the declining block rate is appropriate to account for reductions in the cost of service to residential customers as consumption increases. With no declining block rate, high load factor customers are disadvantaged as the customer charge is reduced and the demand charge is moved into the energy charge. She believes that declining block rates alleviate the disadvantage.1029 Ms. Talkington illustrated the impact of Mr. Benedict’s suggestion to phase out the declining block rate for RS customers. Approximately 54 percent of ETI’s residential customers use more than 1,000 kWh in January and February. For a customer using 3,000 kWh in a winter month of November-April, this customer’s bill would increase by 16.28 percent or about $48 over current rates. (Of ETI’s total number of RS customers, approximately 10 percent use 3,000 kWh or more in the months of January and February.) For that same customer, ETI’s as-filed proposal shows an increase of 11.96 percent or approximately $35. Mr. Benedict’s proposal is $13 greater than ETI’s proposal for one winter month at 3,000 kWh. That dollar amount is over a third of the total increase ETI is proposing.1030 After Mr. Benedict’s proposed phase-out is completed, based on the proposed residential rates in the Company’s case, the residential rate would be $0.06887 per kWh in both summer and winter. A customer using 3,000 kWh in a winter month of November-April would see an increase of 24.89 percent or about $73 over current rates. After the final phase out, Mr. Benedict’s proposal is $38 per month greater than ETI’s as-filed proposal of $35 for one winter month at 3,000 kWh.1031 1027 Staff Ex. 7 (Abbott Direct) at 27. 1028 ETI Ex. 67 (Talkington Rebuttal) at 13, Ex. MLT-R-1. 1029 Id. at 14. 1030 Id. at 15. 1031 Id. at 15-16. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 319 PUC DOCKET NO. 39896 Ms. Talkington further noted that rate design professionals always take into consideration the effect on customer bills. Even though Mr. Benedict proposes to implement the change over the next three rate cases, she concludes there will still be winners and losers within the residential class as a result of his proposed change. According to Ms. Talkington, some customers have made decisions about investing in electric appliances based on the current rate design. The elimination of the declining block in the winter time changes the economics of customer decisions that have already been made. She believes that great caution needs to be exhibited and very good reasons need to be demonstrated before changes are made to the rate design. She recommended that if a change to the rate structure is recommended, the initial phase-in should be reduced to 10 percent rather than one- third and subsequent reductions should be reviewed for consideration at the occurrence of each rate case filing and not mandated at this time.1032 The ALJs concur with OPC and Staff that the structure of the declining block winter rates provide a disincentive to energy efficiency. However, ETI provided evidence that OPC’s suggested changes, combined with ETI’s proposed rate increase, will have too great an impact. OPC suggested a one-third reduction in the differential, while Ms. Talkington suggested a 10 percent reduction, with subsequent reductions reviewed before being mandated. The ALJs recommend an initial 20 percent reduction, which should alleviate some of ETI’s concerns but still reduce the block differential sufficiently to move towards compliance with the energy goals set out in PURA. The ALJs further recommend that 20 percent subsequent reductions of the differential be required in the next three rate cases unless ETI provides sufficient evidence that such changes are unjust and unreasonable. XI. FUEL RECONCILIATION [Germane to Preliminary Order Issue Nos. 21-31] In the application, ETI seeks to reconcile approximately $1.3 billion in fuel and purchased power expenses incurred over the 24 month Reconciliation Period. Summaries of ETI’s total fuel and purchased power expenses and over/under recovery balance are shown below. 1032 ETI Ex. 67 (Talkington Rebuttal) at 15-17. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 320 PUC DOCKET NO. 39896 Fuel Reconciliation Gas and Oil $616,248,686 Emissions Allowance 360,236 Coal 90,821,317 Total Fuel: $707,430,239 Purchase Power Expense 990,041,434 Off-system Sales Revenues (376,671,969) Total Purchased Power: $613,369,465 Total Fuel Costs: $1,321,799,704 Over-recovery Balance: $243,339,353 Special Circumstances $99,715 Sources: ETI Ex. 3 Schedules I-16, H-12.4a-g, H-12.5b-e, I-21; ETI Ex. 11 (McCloskey Direct); ETI Ex. 23 (Zakrzewski Direct). ETI contends, and the evidence presented at the hearing demonstrates, that these fuel factor expenses were eligible for reconciliation and were reasonable and necessary to provide reliable service to ETI’s customers during the Reconciliation Period. With the exception of three minor issues that are discussed below, none of the intervenors raised a substantive issue with respect to ETI’s fuel reconciliation request. During the Reconciliation Period, ETI’s Texas fuel factor revenues over-recovered total fuel and purchased power expense by $243,339,353, inclusive of interest. The Commission authorized the refund of the fuel over-recovery balance in Docket Nos. 37580, 38403, and 38967. ETI proposes that the amount of any fuel over-recovery balance not already refunded or authorized for refund be rolled forward as the beginning balance for the next reconciliation period.1033 P.U.C. SUBST. R. 25.236(d)(1) states that in a fuel reconciliation proceeding, the utility has the burden of showing that: (A) its eligible fuel expenses during the fuel reconciliation period were reasonable and necessary expenses incurred to provide reliable electric service to retail customers; 1033 ETI Ex. 40 (Thiry Direct) at 7. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 321 PUC DOCKET NO. 39896 (B) if its eligible fuel expenses for the reconciliation period included an item or class of items supplied by an affiliate of the electric utility, the prices charged by the supplying affiliate to the electric utility were reasonable and necessary and no higher than the prices charged by the supplying affiliate to its other affiliates or divisions or to unaffiliated persons or corporations for the same item or class of items; and (C) it has properly accounted for the amount of fuel-related revenues collected pursuant to the fuel factor during the reconciliation period. In Docket No. 15102, an EGSI fuel reconciliation case, the Commission explained the traditional prudence standard to be applied in reviewing decisions made by the utility: The exercise of that judgment and the choosing of one of that select range of options which a reasonable utility manager would exercise or choose in the same or similar circumstances given the information or alternatives available at the point in time such judgment is exercised or option is chosen. There may be more than one prudent option within the range available to a utility in any given context. Any choice within the select range of reasonable options is prudent, and the Commission should not substitute its judgment for that of the utility . . . . The reasonableness of an action or decision must be judged in light of the circumstances, information, and available options existing at the time, without benefit of hindsight.1034 ESI purchases power and procures fossil fuels on behalf of the individual Operating Companies. Fossil fuel costs are borne directly by the Operating Company that contracts for and uses the fuel. Once resources are procured to meet forecasted demand, the system is operated during the current day using all of the resources available to the system to meet the total system demand. Throughout the course of the day, system operators may modify planned operations to maintain reliability, take advantage of less-expensive resources in the hourly wholesale power markets, or make off-system sales. For example, when spot market power purchases are available at a cost 1034 Application of Gulf States Utilities Company to Reconcile its Fuel Costs, Docket No. 15102, Order on Rehearing at 2 (Jun. 24, 1997). SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 322 PUC DOCKET NO. 39896 lower than the cost of energy that can be generated by units owned by the Operating Companies, that energy is purchased to displace owned generation, subject to operating constraints.1035 Expenses for coal, gas, power purchases, and fuel oil are incurred directly by the respective Operating Company. For example, if coal is purchased for ETI’s share of Nelson Station, Unit 6, then ETI is responsible for the invoiced cost and makes payment directly to the supplier. Wholesale power, purchased and sold for the system, however, is accounted for per the terms of the System Agreement. After dispatch, or after-the-fact, the System Agreement prescribes an accounting protocol to bill the costs of operating the system to the individual Operating Companies.1036 The following Fuel Reconciliation-related issues were uncontested:  Natural Gas Purchases ETI witness Karen McIlvoy presented direct testimony describing ETI’s natural gas procurement policies and strategies. She explained that the Company buys gas through a long-term contract with Enbridge, through participation in the monthly and daily markets depending on fuel needs, and on a delivered-to-plant basis or arrange for transportation to the plant. Ms. McIlvoy described how the gas buyers for ETI survey the markets and solicit offers for gas supplies. Ms. McIlvoy also provided a comparison of the Company’s gas costs to the Inside FERC and Gas Daily published indices for the Houston Ship Channel.1037 No party challenged the Company’s natural gas purchases.  Fuel Oil Ms. McIlvoy testified that the Company purchased fuel oil for start-up and flame stabilization at certain units. Fuel oil can also be used for emergency back-up fuel or as an economic alternative to natural gas at certain units. During the Reconciliation Period, the Company purchased 1035 ETI Ex. 40 (Thiry Direct) at 18-21. 1036 ETI Ex. 39 (Cicio Direct) at 31-37. 1037 ETI Ex. 28 (McIlvoy Direct) at 23, Ex. KDM-3. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 323 PUC DOCKET NO. 39896 all fuel oil on a short-term basis from spot market sources after solicitation of bids from multiple potential suppliers.1038 No party contested ETI’s fuel oil costs.  Longer-Term Purchased Power ETI witness Robert R. Cooper addressed the Entergy system’s long-term planning process and described the Strategic Resource Plan process. He explained how the system determined its capabilities and needs for additional resources to reliably serve system load requirements. Mr. Cooper described the process by which the system developed requests for proposals and analyzed a combination of capacity and firm energy contracts to satisfy the system’s identified resource needs.1039 A portion of these system purchases was allocated to ETI. No party proposed a disallowance of these purchases on the basis of prudence.  Short-Term Purchased Power Ms. Thiry described the Power Marketing Team’s procurement strategies, practices and procedures during the Reconciliation Period. Ms. Thiry testified that the Power Marketing Team fulfilled its objective of purchasing energy in the wholesale market when it was more economical than using the system’s generation and in order to maintain system reliability. Ms. Thiry demonstrated that third-party purchases for the system compared favorably to market price indices and to proxy costs of avoided generation.1040 The Power Marketing Team maintained effective cost controls and procured a diverse portfolio of product to provide electricity for customers at a reasonable cost.1041 No party contested the prudence of ETI’s short-term power purchases.  Coal Commodity and Transportation ETI has ownership interest and/or obtains power through Schedule MSS-4 of the Entergy System Agreement, in two coal-burning generating units – Nelson and BCII/U3. ETI owns a 1038 ETI Ex. 28 (McIlvoy Direct) at 5-6. 1039 ETI Ex. 34 (Cooper Direct) at 6-10. 1040 ETI Ex. 40 (Thiry Direct) at 24. 1041 Id. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 324 PUC DOCKET NO. 39896 29.75 percent interest in Nelson 6 and operates the unit. ETI owns a 17.85 percent interest in BCII/U3, but the unit is operated by a third party. ETI witness Ryan Trushenski, the Manager of Coal Supply for ESI, testified that ETI prudently managed its coal supply and transportation expenses during the Reconciliation Period.1042 With respect to coal and transportation expenses at Nelson 6, ETI obtained coal during the Reconciliation Period under a supply contract previously reviewed by the Commission, and entered into a new coal supply contract after a competitive bid process. ETI chose the supplier with the lowest priced coal that met the specifications necessary for use at Nelson 6. Similarly, ETI arranged for transportation of coal according to transportation contracts previously reviewed in prior fuel reconciliations. When those contracts expired, ETI initiated a competitive bid process and chose the lowest cost option available that met its requirements. With respect to BCII/U3, ETI incurred costs to run the unit and took reasonable steps to ensure that the third party operator properly charged for coal and transportation expenses under an arrangement previously reviewed and approved in prior fuel reconciliations.1043 No party challenged the reasonableness and necessity of ETI’s coal or transportation expense during the Reconciliation Period The three contested issues are discussed below. A. Spindletop Gas Storage Facility During the Reconciliation Period, ETI incurred $10,261,663 of non-fuel expense associated with operating the Spindletop Facility. Cities challenged ETI’s use of the Spindletop Facility, arguing that the costs of operating it outweigh the benefits gained from it. For the same reason he challenged the Spindletop Facility costs associated with rate base, Cities witness Nalepa also challenges ETI’s non-fuel expense associated with the facility. Specifically, Mr. Nalepa recommends that ETI’s total fuel reconciliation balance be reduced by $6,595,290, which he calculates as the difference between the $10,261,633 non-fuel operational costs associated with the Spindletop Facility over the Reconciliation Period and the costs of alternative sources of providing a 1042 ETI Ex. 33 (Trushenski Direct) at 2. 1043 Id. at 11-13. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 325 PUC DOCKET NO. 39896 reliable and flexible gas supply over the same period.1044 In Section V.H., above, the ALJs rejected Cities’ contention that the Spindletop Facility is not used or useful. For the same reason they rejected Cities’ Spindletop Facility arguments relevant to rate base, the ALJs also reject Cities’ Spindletop Facility arguments relevant to Fuel Reconciliation. B. Use of Current Line Losses for Fuel Cost Allocation Cities propose that the allocation of fuel costs incurred over the Reconciliation Period reflect the current line loss study performed by ETI for this case and recommended for approval on a going forward basis. In the fuel reconciliation case, ETI proposes to allocate costs to customers using a line loss study performed in 1997, which Cities claim does not reflect the current cost of providing service to the current wholesale customers and to the various retail customers.1045 According to Cities, updating ETI’s allocation of fuel costs to reflect current line losses and the cost of providing service to customers results in a $3,981,271 reduction to the Texas retail fuel expenses incurred over the Reconciliation Period.1046 ETI responds that the Cities’ recommendation is unprecedented. It notes that the Commission’s substantive rules require use of “a commission-approved adjustment to account for line losses corresponding to the voltage at which the electric service is provided.”1047 Moreover, ETI argues that retroactive use of new loss factors to calculate its fuel over/under-recovery balance would result in a mismatch between the revenues recovered under the fuel factor and the costs billed and allocated to the various customer classes.1048 Fuel costs are collected through Commission-approved fixed fuel factors. One of the elements the fuel factor is required to take into account is line losses. P.U.C. SUBST. R. 25.237(c)(2)(B) states that the utility must prove that: “the proposed fuel factors utilize a 1044 Cities Ex. 6 (Nalepa Direct) at 42-43; Cities Initial Brief at 84. 1045 Cities Ex. 6 (Napala Direct) at 44; see also Tr. at 1469-1470. 1046 Cities Ex. 6 (Napala Direct) at 47, Table 14. 1047 ETI Ex. 58 (McCloskey Rebuttal) at 2, quoting P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added). 1048 Tr. at 1484. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 326 PUC DOCKET NO. 39896 commission-approved adjustment to account for line losses corresponding to the voltage at which the electric service is provided.”1049 If the Commission were to adopt Cities’ recommendation that the newly-developed line losses be used in the reconciliation of fuel costs, the allocation of those costs would not match the collections (determined through the use of historical line losses). This mismatch could result in some customers receiving more than they are entitled and others receiving less than they are entitled. The ALJs find that the Commission’s rules require the use of Commission-approved line losses that were in effect at the time fuel costs were billed to customers in a fuel reconciliation. The ALJs, therefore, recommend that the Commission reject the Cities’ proposed adjustment. C. ETI’s Special Circumstances Request In the application, ETI seeks to include $99,715 in the Fuel Reconciliation to allow it to recover “the reversal of certain credits that were previously included in the Company’s [Incremental Purchased Capacity Rider] Rider IPCR.”1050 ETI witness Zakrzewski explained that the FERC revised the amount of purchased capacity-related production costs allocable to ETI through the FERC-approved Rough Production Cost Equalization mechanism for allocating production costs among the Operating Companies. As Mr. Zakrzewski explained, the result of the decision was a recalculation of ETI’s capacity costs recoverable through the Commission-approved Rider IPCR, which expired during the Reconciliation Period.1051 During the hearing, no party contested ETI’s special circumstances request of $99,715 with regard to the IPCR-related adjustment. For the first time in its Initial Brief, however, Cities opposed the request, asserting that it conflicts with the settlement reached in Docket No. 37744.1052 The ALJs are not swayed by Cities’ argument. As pointed out by ETI,1053 Cities provided no testimony or other evidence to support its position. Furthermore, Cities failed to explain how a settlement 1049 P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added). 1050 ETI Ex. 23 (Zakrzewski Direct) at 13. 1051 Id. 1052 Cities Initial Brief at 86. 1053 ETI Reply Brief at 93. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 327 PUC DOCKET NO. 39896 agreement reached in Docket No. 37744 could or should trump the FERC’s jurisdiction to determine the amount of purchased capacity costs attributable to ETI. The only evidence in the record supports ETI’s recovery of these costs. Accordingly, the ALJs recommend that these FERC-imposed costs should be found to be recoverable and Cities’ request to deny their recovery should be rejected. In summary, the ALJs conclude that, consistent with the requirements of P.U.C. SUBST. R. 25.236(d)(1), ETI met its burden to prove that: (1) its eligible fuel expenses during the Reconciliation Period were reasonable and necessary expenses incurred to provide reliable electric service to its retail customers; (2) the prices charges by its affiliates were reasonable and necessary and no higher than the prices charged by the supplying affiliates to other affiliates or to unaffiliated persons; and (3) ETI has properly accounted for the amount of fuel-related revenues collected pursuant to the fuel factor during the Reconciliation Period. XII. OTHER ISSUES A. MISO Transition Expenses [Germane to Preliminary Order Issue Nos. 6-8 and Docket No. 39741 Preliminary Order Issue Nos. 1-9] Entergy is seeking to transfer operational control of the Entergy Operating Companies’ transmission assets to the MISO Regional Transmission Organization (RTO). ETI expects its share of the costs for this transfer will include approximately $17 million of expense.1054 ETI has made two alternate proposals to recover these expenses. ETI’s first proposal requests the Commission to approve a deferred accounting of its transition expense incurred on or after January 1, 2011, and to approve accrual of interest on the deferred amount at ETI’s overall rate of return. Under this proposal, ETI would present the resulting regulatory asset for review in a future proceeding. ETI originally requested this deferred accounting in Docket No. 39741, which was later consolidated into this case for all purposes. In its Preliminary Order in Docket 39741, the Commission stated that it had authority to allow such a deferral of costs “when it is necessary to carry out a provision of PURA.” It also stated that whether ETI’s request met this requirement “hinges on the factual issue of necessity . . . .” 1054 ETI Ex. 42 (Lewis Supplemental Direct) at 5. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 328 PUC DOCKET NO. 39896 As an alternative proposal, ETI requested the Commission to include $4 million of transition expense in base rates set in the present case, based on a three-year amortization of a total of $12 million in MISO transition expenses. ETI’s Test Year MISO transition expenses totaled only $916,535, but ETI’s request for deferred accounting addressed expenses incurred on or after January 1, 2011, which is after the Test Year concluded. ETI argues that its request is a conservative known and measureable change because the post-Test-Year expenses will be significantly more than $4 million per year. Further, these costs would be removed from ETI’s cost of service if its deferred accounting proposal is approved. As noted, ETI’s proposals concern MISO transition expenses incurred on or after January 1, 2011. However, ETI also incurred $263,908 in these expenses during the 2010 portion of the Test Year. ETI has proposed a five-year amortization of this amount ($52,800 per year), assuming either its primary proposal or its alternative proposal is adopted. However, if ETI’s primary and alternative proposals are both rejected, ETI requested that no reduction be made to its total Test Year amount of $916,535.1055 Cities, TIEC, State Agencies, and Staff opposed ETI’s requests. They argue that ETI failed to establish that the proposed deferred accounting is necessary to carry out a provision of PURA, as required by the Commission’s Preliminary Order. They also contended that ETI’s alternate request to include $4 million in base rates is not a known and measureable change and should be disallowed. The ALJs recommend that the Commission deny ETI’s request for deferred accounting of its MISO transition expenses to be incurred on or after January 1, 2011. However, the ALJs do recommend that the Commission authorize ETI to include $2.4 million of MISO transition expense in base rates set in the present case, based on a five-year amortization of $12 million in total projected expenses. 1055 ETI Ex. 42 (Lewis Supplemental Direct) at 4 and Adjustment No. 16.L. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 329 PUC DOCKET NO. 39896 1. Deferred Accounting In support of its deferred accounting request, ETI cited State v. Public Utility Comm’n of Texas.1056 In that case, the Texas Supreme Court stated that a deferred accounting is “necessary” when it will “ensure that the requirements of [PURA] are met.”1057 In ETI’s opinion, deferred accounting is necessary in the present case to ensure that PURA §§ 36.051 and 36.003(a) are met (i.e., that utilities have a reasonable opportunity to recover their expenses and receive reasonable rates). ETI also relied on Hammack v. Public Utility Commission of Texas, which stated that “a need . . . is a relative requirement, ranging from an imperative need to one that is minimal . . . .”1058 ETI-witness Brett Perlman testified that deferred accounting is also necessary to ensure the requirements of PURA § 31.001(c) are carried out.1059 That section encourages development of a competitive wholesale electric market. ETI noted that the Hammack opinion stated that Section 31.001(c) amounts to a “legislative directive that the Commission formulate policies responsive to the needs of the emerging competitive wholesale market.”1060 Therefore, ETI asserted that RTO membership and deferred accounting are necessary because they will ensure that the Commission meets its obligation under Section 31.001(c). More specifically, ETI stated, both RTO membership and deferred accounting itself constitute examples of policies required by section 31.001(c) to support wholesale competition. Therefore, ETI argues that its request for deferred accounting should be approved because it is necessary to carry out PURA §§ 36.051, 36.003, and 31.001(c).1061 Cities argue that ETI’s request for deferred accounting of MISO transition expenses should be denied because deferred accounting is not necessary to carry out any requirement of PURA. 1056 883 S.W.2d 190 (Tex. 1994). 1057 883 S.W.2d at 194. 1058 Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet. denied). 1059 ETI Ex. 43 (Perlman Supplemental Direct) at 7. 1060 131 S.W.3d at 723. 1061 ETI’s Initial Brief at 231-234; ETI Ex. 42 (Lewis Supplemental Direct) at 2-4; ETI Ex. 43 (Perlman Supplemental Direct) at 5-7. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 330 PUC DOCKET NO. 39896 Cities witness James Brazell stated that ETI’s proposed transition to MISO is not mandatory, and the anticipated expenses are not extraordinary. He added that ETI has been exploring membership in an RTO for over ten years and those costs have historically been included in ETI’s base rates; therefore, he concluded that deferred accounting was not necessary in the past and is not necessary now. Cities stressed that ETI conceded that deferred accounting of these expenses is not necessary to maintain its financial integrity, and in Cities’ opinion, both State v. Public Utility Comm’n of Texas,1062 and the Commission’s Preliminary Order require a showing of impairment of financial integrity to conclude that deferred accounting is necessary to comply with PURA § 36.051. Cities also stated that ETI failed to show that deferred accounting is necessary to comply with PURA §§ 36.003 and 31.001(c); therefore, Cities argues that ETI’s request for deferred accounting should be denied. TIEC also opposed ETI’s request for deferred accounting, arguing that ETI failed to demonstrate that it is necessary to carry out PURA §§ 36.051, 36.003, or 31.001(c). TIEC witness Jeffry Pollock stated there is no indication that deferred accounting treatment is necessary for ETI to earn a reasonable return on its invested capital or that denying the deferred accounting would prevent ETI from having just and reasonable rates. Further, Mr. Pollock asserted there is no evidence that a lack of deferred accounting treatment for ETI would prevent Entergy from pursuing its MISO proposal.1063 Mr. Pollock added that ETI has incurred other similar costs to carry out various purposes of PURA without deferred accounting. For example, since 2005, ETI has spent nearly $20 million pursuing various similar activities, including transitioning to competition, investigating RTO options, examining changes to the Entergy System Agreement, and supporting the Entergy OATT. Yet, ETI did not seek deferred accounting for any of those costs. Finally, Mr. Pollock testified that the projected transition costs are not material. He noted that ETI expects to incur $17 million of transition costs.1064 This equates to $5.8 million per year, which is only 1 percent of ETI’s Test Year operating revenues, according to Mr. Pollock. In his opinion, this level 1062 883 S.W.2d 190 (Tex. 1994). 1063 TIEC Ex. 1 (Pollock Direct) at 46-47. 1064 ETI Ex. 42 (Lewis Supplemental Direct) at 5. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 331 PUC DOCKET NO. 39896 of MISO transition costs is easily subsumed in the normal variation in ETI’s year-to-year expenses.1065 TIEC also disagreed with ETI’s interpretation of State v. Public Utility Comm’n of Texas.1066 In TIEC’s view, that case held that deferred accounting is necessary only when needed to protect the financial integrity of the utility. Likewise, TIEC disagreed with ETI’s argument that Hammack1067 held that “need” is a relative requirement that must be viewed in light of legislative policy directives.1068 TIEC noted that Hammack had nothing to do with deferred accounting. Instead, it was limited to the issue of whether, in granting a certificate of convenience and necessity for a transmission line under PURA §37.056, the Commission should include evidence that considered customers and market participants throughout the state.1069 In TIEC’s view, the Hammack case is irrelevant in determining whether deferred accounting is necessary to carry out the provisions of PURA §§ 36.003, 36.051, and 31.003(c). State Agencies made similar arguments. Commission Staff also argues that ETI did not establish why deferred accounting is necessary to carry out a provision of PURA. In Staff’s view, the applicable court cases and other precedent required ETI to show that deferred accounting is necessary to maintain its financial integrity, in order to carry out the provisions of PURA § 36.051. Staff argues that the Commission’s Preliminary Order did not reject the financial integrity standard when it stated: “[t]his standard is not appropriate, however, for all circumstances and the Commission has applied different standards in various circumstances.”1070 Rather, Staff stated, the Commission merely declined to designate a specific standard. 1065 ETI Ex. 1 (Pollock Direct) at 48-49 and Ex. JP-8. 1066 883 S.W.2d 190 (Tex. 1994). 1067 Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet. denied). 1068 ETI Initial Brief at 232-233. 1069 Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 724 (Tex .App.−Austin 2004, pet. denied). 1070 Application of Entergy Texas, Inc. for Authority to Defer Expenses Related to its Proposed Transition to Membership in The Midwest Independent Transmission System Operator, Docket No. 39741 Preliminary Order at 9 (Sep. 2, 2011). SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 332 PUC DOCKET NO. 39896 Staff also rejected ETI’s argument that deferred accounting will “ensure that the Commission meets its obligation under Section 31.001(c) to support the achievement of a competitive wholesale market.”1071 First, Staff noted, the Commission stated in the Preliminary Order that merely showing movement towards a policy goal is not a sufficient standard upon which to approve deferral.1072 Thus, ETI’s statement that deferred accounting will “support” wholesale competition addresses a standard that the Commission already rejected. Second, Staff argues that ETI failed establish that deferred accounting is “necessary” to support a competitive wholesale market or that failure to allow deferred accounting would prevent that goal. In other words, ETI did not show that, absent deferral, it would not join MISO; thus, ETI did not show how deferral would “ensure” that it joins an RTO. Therefore, Staff concluded, because ETI failed to prove that deferred accounting is necessary to carry out any provision of PURA, ETI’s request should be denied. In response to these arguments, ETI noted that no party disputed that the Commission may grant deferred accounting “when it is necessary to carry out a provision of PURA.” It also argues that Staff and intervenors misinterpreted State v. Public Utility Comm’n of Texas1073 as holding that deferred accounting is necessary to carry out PURA § 36.051 only when a utility’s financial integrity is at stake. Although lack of financial integrity is an indication that PURA § 36.051 has not been carried out, ETI noted that this section contains other express requirements that can be met through deferred accounting, such as ensuring utilities a reasonable opportunity to recover their costs. ETI also cited other Commission cases in which it authorized deferred accounting when financial integrity was not at stake, such as deferral of rate case expenses and merger costs for subsequent review and recovery.1074 ETI added that deferred accounting would permit the Commission to review ETI’s transition expenses in a subsequent proceeding, after determining whether ETI’s transition to MISO is in the public interest. Thus, under ETI’s proposal, there is no risk that ETI would recover such costs absent a finding that they are reasonable and necessary. 1071 ETI Initial Brief at 234. 1072 Docket No. 39741, Preliminary Order at 11. 1073 883 S.W.2d 190 (Tex. 1994). 1074 ETI Reply Brief at 95-96. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 333 PUC DOCKET NO. 39896 As for Staff and TIEC’s argument that deferred accounting is not necessary to carry out PURA § 31.001(c), ETI argues that the “necessary” standard is not a “but for” test. In response to arguments that the proposed deferred accounting will merely further policy objectives of Section 31.001(c), which the Commission has deemed insufficient to meet the “necessary” standard,1075 ETI reiterated that the Hammack opinion held that “the Commission’s interpretation of need must be viewed in light of the legislative directive that the Commission formulate policies responsive to the needs of the emerging competitive wholesale market,” as well as “overall policy objectives.”1076 Thus, ETI argues, that it has demonstrated that deferred accounting is necessary to carry out Section 31.001(c) – i.e., it will “ensure” that the requirements of that provision are carried out, and in particular ensure that the Legislature’s specific instruction to develop the wholesale market is carried out.1077 Although ETI’s proposal for deferred accounting has some practical appeal, the ALJs conclude that ETI has not shown that it is necessary to carry out a provision of PURA. The ALJs find that ETI was not required to show that a deferred accounting is necessary to maintain its financial integrity, as argued by intervenors. In State v. Public Utility Comm’n of Texas,1078 the Texas Supreme Court held that preserving the financial integrity of a utility was necessary to carry out a provision of PURA, and thus justified deferred accounting for certain expenses in that case, but the court did not hold that preserving financial integrity was the sole basis upon which a deferred accounting could be approved. Likewise, in its Preliminary Order for the present case, the Commission stated: “This standard [financial integrity] is not appropriate, however, for all circumstances and the Commission has applied different standards in various circumstances, although none of these standards or circumstances has been reviewed by any court.”1079 On the other hand, the ALJs also find that ETI’s contention that deferred accounting of the MISO transition expenses will help the development of a competitive wholesale electric market, as described in 1075 Docket No. 39741, Preliminary Order at 7. 1076 Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet. denied). 1077 ETI Reply Brief at 97-99. 1078 883 S.W.2d 190 (Tex. 1994). SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 334 PUC DOCKET NO. 39896 PURA § 31.001(c), is not sufficient to authorize deferred accounting. Again, the Commission stated in the Preliminary Order that “to carry out a provision of PURA” means more than undefined progress or movement towards a statutory objective.1080 The Commission made clear that ETI’s burden was not only to show that a provision of PURA would be carried out by an accounting deferral of the MISO transition expenses, but that the deferral is necessary to carry out that provision. The Commission added that necessity was a question of fact that “can only be determined after development of an adequate factual record that demonstrates the necessity, of whatever degree.”1081 Intervenors argue that Entergy’s efforts to transfer operational control of the Entergy Operating Companies’ transmission assets to MISO will proceed with or without the deferred accounting requested by ETI; thus, deferred accounting is not necessary. Likewise, intervenors argue that ETI’s alternate proposal to recover the transition costs through base rates shows that deferred accounting is not necessary. ETI, however, asserted that necessity should not be considered a “but for” requirement. It noted that no provision of PURA would be impossible to carry out absent a deferral of rate case expenses or merger expenses, yet the Commission has allowed deferred accounting of such expenses in other cases. ETI also cited the statement in Hammack v. Public Utility Commission of Texas that “a need . . . is a relative requirement, ranging from an imperative need to one that is minimal . . . .”1082 Intervenors criticized ETI’s reliance on the Hammack case because it concerned a transmission line. While that is correct, the case does make the general point that the question of need is not an absolute “but for” test. This is also consistent with the Commission’s statement in the Preliminary Order that ETI’s burden was to demonstrate necessity, “of whatever degree.” ETI’s complaint is that its MISO transition expenses will soon increase above the Test Year amount, from $916,535 for the Test Year to over $5 million per year, but it will not be able to recover the increased costs through normal Test Year cost-of-service ratemaking principles. Thus, 1079 Docket No. 39741, Preliminary Order at 9 (Nov. 22, 2011). 1080 Id. at 11. 1081 Id. at 8. 1082 Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet. denied). SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 335 PUC DOCKET NO. 39896 although ETI’s financial integrity may not be jeopardized, ETI argues that it nevertheless will not be able to have a reasonable opportunity to recover its expenses and receive reasonable rates as required by PURA §§ 36.051 and 36.003(a). Therefore, ETI believes the proposed deferred accounting is necessary to carry out those provisions of PURA. The ALJs find that the essence of ETI’s complaint is that regulatory lag works against it in this particular situation. But as noted by the court in State v. Public Utility Comm’n of Texas, regulatory lag is an ordinary element of risk for utilities.1083 One of the characteristics of Test Year cost-of-service ratemaking is that some expenses upon which rates are based may go up and others may go down during the time the rates are in effect. Such changes can be corrected in future ratemaking proceedings, but in this case ETI desires to ensure that it will recover all of its MISO transition costs. But State v. Public Utility Comm’n of Texas and the Commission’s Preliminary Order in this case make clear that eliminating the normal effects of regulatory lag by allowing a deferred accounting should not be undertaken lightly. If ETI’s arguments were taken to their extreme, a utility could obtain deferred accounting any time it anticipated a post Test Year increase in a particular expense, under the argument that it must be allowed to recover all of its expenses to carry out the requirements of PURA §§ 36.051 and 36.003(a). In this case, ETI’s estimated MISO transition costs will equal about $5.8 million per year. As Mr. Pollock noted, this is only one percent of ETI’s Test Year operating revenues, which may easily be subsumed in the normal variation in ETI’s year-to-year expenses. Under these circumstances, ETI has not shown that granting its requested deferred accounting is necessary to carry out the requirements of PURA §§ 36.051 and 36.003(a) that it receive just and reasonable rates. Therefore, the ALJs recommend that the Commission deny ETI’s request for deferred accounting treatment of its MISO transition expenses to be incurred on or after January 1, 2011. 1083 883 S.W.2d 190, 196 (Tex. 1994). SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 336 PUC DOCKET NO. 39896 2. Base Rate Recovery As mentioned above, if the Commission denies ETI’s request for deferred accounting, ETI requested the Commission to include $4 million of MISO transition expense in base rates set in the present case, based on a three-year amortization of $12 million in total projected expenses. Cities disputed the amount of MISO expenses ETI requested in this proposal. Cities witness Mark Garrett testified that a $4 million annual expense is inconsistent with ETI’s own projected costs. The Test Year expenses were $916,535, and the actual expenses incurred during January through November 2011 were only $2.513 million, which annualized would be $2.742 million.. For 2013, ETI projected MISO transition expenses of only $2.587 million, although ETI’s projected 2012 level of $8.9 million. However, Mr. Garrett added that 2012 is an estimated level and is not consistent with actual 2011 results. In his opinion, the actual 2011 level of about $2.7 million or the expected 2013 level of about $2.6 million should be the outside range of what the Commission should use for setting prospective rates. In any event, however, Cities argue that these projected levels are not sufficiently known and measurable to include for ratemaking purposes. Cities pointed out that it is unknown whether ETI’s proposed move to MISO will even be approved, or whether the ETI will even continue to incur costs toward a MISO transition. Therefore, Cities argues that only the Test Year level of $916,535 should be included in rates, which would result in a downward adjustment of $3,083,462 to ETI’s request.1084 TIEC also argues that ETI’s alternative proposal should be rejected. Mr. Pollock complained that this proposal would allow ETI to recover post Test Year expenses that are not known and measureable. Mr. Pollock noted that ETI’s own estimate of its share of transition costs has changed. When ETI filed its request for deferred accounting in Docket No. 39741, it estimated transition costs of $12 million. Now it estimates costs of $17 million, an increase of over 40 percent. Further, Mr. Pollock stated, ETI based its share of the estimated transition costs by assuming a 17 percent responsibility ratio, but ETI’s future responsibility ratios are not known because they are based on projected growth rates of ETI relative other Entergy Operating Companies. Thus, Mr. Pollock 1084 Cities Ex. 2 (Garrett Direct) at 61-63 and Ex. MG2.14; Cities Initial Brief at 89-91; Cities Reply Brief at 112-113. SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 337 PUC DOCKET NO. 39896 concluded that ETI’s share of future MISO transition costs cannot be appropriately measured.1085 In summary, TIEC argues that the Commission should deny ETI’s request for deferred accounting and should allow ETI to recover only Test Year MISO transition expenses.1086 Commission Staff made arguments similar to Cities and TIEC.1087 In response, ETI argues that the $4 million annual expense requested is known and measurable. ETI noted that it already incurred over $3.6 million in transition expense in the nine months since the end of the Test Year,1088 which equates to $4.8 million on an annua [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/4062193. Public record. Not legal advice.