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.

ACCEPTED 03-14-00735-CV 5104240 THIRD COURT OF APPEALS AUSTIN, TEXAS 4/30/2015 2:54:51 PM JEFFREY D. KYLE CLERK FILED IN NO. 03-14-00735-CV 3rd COURT OF APPEALS AUSTIN, TEXAS 4/30/2015 2:54:51 PM JEFFREY D. KYLE ENTERGY TEXAS, INC., ET AL., Clerk Appellants, v. PUBLIC UTILITY COMMISSION OF TEXAS, INC., ET AL., Appellees. B RIEF OF A PPELLEE Filed by: Public Utility Commission of Texas KEN PAXTON ELIZABETH R. B. STERLING Attorney General of Texas State Bar No. 19171100 elizabeth.sterling@texasattorneygeneral.gov CHARLES E. ROY First Assistant Attorney General DOUGLAS B. FRASER State Bar No. 07393200 doug.fraser@texasattorneygeneral.gov JAMES E. DAVIS Deputy Attorney General for Civil Litigation DANIEL C. WISEMAN State Bar No. 24042178 daniel.wiseman@texasattorneygeneral.gov JON NIERMANN Chief, Environmental Protection Environmental Protection Division Division P.O. Box 12548, MC-066 Austin, Texas 78711-2548 Assistant Attorneys General: 512.463.2012 512.457.4616 (fax) April 30, 2015 Oral Argument Requested  Table of Contents Table of Contents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i Index of Authorities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v Glossary.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . viii Statement of the Case. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi Statement Regarding Oral Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi Issues Presented.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xii Issue 1: Did the Commission reasonably interpret how its prior ambiguous order in PUC Docket 37744 (the Black-box Order) treated the Hurricane Rita regulatory asset? (Responds to Entergy Issue 1). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xii Issue 2: Does substantial evidence support the Commission’s decision to include Entergy’s 1997 ice-storm repair expenses when computing the utility’s insurance reserve? (Responds to OPUC Issue). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xii Issue 3: Does substantial evidence support the Commission’s decision that Entergy failed to prove that certain purchased- power capacity costs were known-and-measurable changes to those expenses in the test year? (Responds to Entergy Issue 2). . . xii Issue 4: Does substantial evidence support the Commission’s decision that Entergy failed to prove that predicted transmission-equalization charges were known-and- measurable changes to those costs in the test year? (Responds to Entergy Issue 3). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xii Statement of Facts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 I. Procedural History.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 II. Rate Setting.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 i  A. Rate Base.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 1. Hurricane Rita Regulatory Asset. . . . . . . . . . . . . . . 4 2. Self-Insurance Storm Reserve and the 1997 Ice Storm.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 B. Reasonable and Necessary Expenses.. . . . . . . . . . . . . . . . 6 Summary of the Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 I. Standard of Review. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Substantial-evidence Standard.. . . . . . . . . . . . . . . . . . . . . . . . . 10 Arbitrary-and-capricious Standard. . . . . . . . . . . . . . . . . . . . . . . 11 II. The district court properly affirmed the Commission’s decision about the amount of the Hurricane Rita regulatory asset to include in Entergy’s rate base. (Responds to Entergy Issue 1). . . . . . . . . . . . . . . . . . . . . . . . . . . 11 A. Factual Background. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 B. Substantial evidence supports the Commission’s reasonable interpretation of its prior, ambiguous order.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 1. The Black-box Order decided the Rita Asset issue.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Securitization Docket.. . . . . . . . . . . . . . . . . . . . . . . . 16 The statute requires action in the next rate case.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Which is the next rate case?. . . . . . . . . . . . . . . . . . . 18 ii  No objection to the regulatory asset or amortizing it. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 All issues resolved in the Black-box Order. . . . . . 20 2. The Court should defer to the Commission’s interpretation of its ambiguous Black-box Order.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 III. The Commission properly included the 1997 ice-storm recovery costs in the storm-damage reserve account. (Responds to OPUC Issue). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 A. Background of the storm-reserve account.. . . . . . . . . . . 23 B. The Commission did not decide in earlier dockets whether the 1997 ice-storm expenses were properly charged against the storm-reserve account.. . . . . . . . . . 24 C. The reasonableness and prudence of the 1997 ice- storm expenses was based on the evidence in this case; it was not decided in Docket No. 18249.. . . . . . . . 25 D. Substantial evidence supports the expenses of restoring service after the 1997 Ice Storm.. . . . . . . . . . . 27 E. OPUC’s additional complaints do not show error.. . . . . 29 IV. Substantial evidence supports the Commission’s determination that Entergy failed to meet its burden to prove that predicted purchased-power capacity costs were known-and-measurable changes to the test-year data. (Responds to Entergy’s Issue 2).. . . . . . . . . . . . . . . . . . . . . . . . . 31 A. The Commission uses the utility’s actual expenses during a test year to determine what expenses to include in rates, and they can only be changed for known-and-measurable changes... . . . . . . . . . . . . . . . . . . 31 iii  B. Entergy sought adjustments outside the test year for alleged future capacity expenses.. . . . . . . . . . . . . . . . . . . 33 C. Entergy failed to prove that the adjustments were known-and-measurable changes... . . . . . . . . . . . . . . . . . 37 V. Substantial evidence supports the Commission’s determination that Entergy failed to meet its burden to prove that predicted transmission-equalization charges were known-and-measurable changes to the test-year data. (Responsive to Entergy’s Issue 3)... . . . . . . . . . . . . . . . . 38 A. Entergy recovers transmission equalization expenses through rates... . . . . . . . . . . . . . . . . . . . . . . . . . 39 B. Entergy sought an adjustment based on anticipated post-test-year transmission expenses... . . . . . . . . . . . . . 39 C. Entergy failed to meet its burden, and the Commission denied its requested adjustments.. . . . . . . 42 Prayer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Certificate of Compliance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Certificate of Service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 APPENDICES Commission Order (Docket No. 39896). . . . . . . . . . . . . . . . . . . . . . . . . . . . . A Proposal for Decision (Docket No. 39896). . . . . . . . . . . . . . . . . . . . . . . . . . . B Black-box Order (Docket No. 37744).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C iv  Index of Authorities Cases Page(s) AEP Tex. N. Co. v. Pub. Util. Comm’n, 297 S.W.3d 435 (Tex. App.—Austin 2009, pet. denied). . . . . 22, 23 Anderson v. R.R. Comm’n, 963 S.W.2d 217 (Tex. App.—Austin 1998, pet. denied). . . . . . . . 9, 10 Cent. Power & Light v. Pub. Util. Comm’n, 36 S.W.3d 547 (Tex. App.—Austin 2000, pet. denied). . . . . . . . . 32 Cities of Abilene v. Pub. Util. Comm’n, 146 S.W.3d 742 (Tex. App.—Austin 2004, no pet.). . . . . . . . . 10, 23 Cities of Abilene v. Pub. Util. Comm’n, 854 S.W.2d 932 (Tex. App.—Austin 1993) aff’d in part, rev’d in part on other grounds, 909 S.W. 2d 493 (Tex. 1995)... . . . . . . 21, 22 Cities of Corpus Christi v. Pub. Util. Comm’n, 2008 WL 615417 (Tex. App.—Austin Mar. 5, 2008, no pet.) (mem. op.). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 City of El Paso v. El Paso Elec. Co., 851 S.W.2d 896 (Tex. App.—Austin 1993, writ denied).. . . . . . . . 33 City of El Paso v. Pub. Util. Comm’n, 344 S.W.3d 609 (Tex. App.—Austin 2011, no pet.). . . . . . . . . . . . 33 City of El Paso v. Pub. Util. Comm’n, 883 S.W.2d 179 (Tex. 1994). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10, 11 Entergy Gulf States, Inc. v. Pub. Util. Comm’n, 112 S.W.3d 208 (Tex. App.—Austin 2003, pet. denied).. . . . . . . . 22 Gulf States Utils. Co. v. Pub. Util. Comm’n, 841 S.W.2d 459 (Tex. App.—Austin 1992, writ denied).. . . . . . . . 33 v Cases cont’d Page(s) Meier Infiniti v. Motor Vehicle Bd., 918 S.W.2d. 95 (Tex. App.—Austin 1996, writ denied). . . . . . . . . 30 Pub. Util. Comm’n v. GTE-Sw., Inc., 901 S.W.2d. 401 (Tex. 1995). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Pub. Util. Comm’n v. Gulf States Utils. Co., 809 S.W.2d. 201 (Tex. 1991). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 State Agencies & Insts. of Higher Learning v. Pub. Util. Comm’n, 450 S.W.3d 615 (Tex. App.—Austin 2014, pet. filed). . . . . . . . . . . 22 Tex. Health Facilities Comm’n v. Charter Med.-Dallas, Inc., 665 S.W.2d 446 (Tex. 1984). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10, 11 Tex. Utils. Elec. Co. v. Pub. Util. Comm’n, 881 S.W.2d 387 (Tex. App.—Austin 1994) aff’d in part, rev’d in part on other grounds, 935 S.W.2d 109 (Tex. 1997)... . . . . . . . . . 29 Statutes Tex. Gov’t Code §§ 2001.001–.902. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . viii § 2001.003(1). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 § 2001.174. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Tex. Util. Code §§ 11.01–66.016.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 §§ 39.458–.463. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 § 15.001. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 § 36.006. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4, 7, 21, 32 § 36.051. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3, 7, 31 § 36.064(a).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 § 39.458(a).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 § 39.459(c). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15, 17, 18 § 39.462(a).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17, 18 vi Rules 16 Tex. Admin. Code § 25.5(134). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . x, 7, 32 § 25.231(a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 § 25.231(b). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7, 31, 32 § 25.231(b)(1)(G).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5, 6, 30 § 25.231(c)(2)(C)(iii).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 § 25.231(c)(2)(E). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 § 25.239(c). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 vii  Glossary ALJ Administrative Law Judge APA Administrative Procedure Act, Tex. Gov’t Code §§ 2001.001–.902. Black-box case Tex. Pub. Util. Comm’n, Application of Entergy Texas for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744. Entergy’s last rate case before this case. Black-box Order Tex. Pub. Util. Comm’n, Application of Entergy Texas for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744, available at http://interchange.puc.state.tx.us/WebApp/Interch ange/Documents/37744_1449_686947.PDF (Dec. 13, 2010) (final order setting rates) (37744 Order). A copy is attached as Appendix C. 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 Commission Staff Commission personnel acting as a party in a contested case representing the public interest before the PUC Entergy Entergy Texas, Inc., the utility asking the Commission to set rates in this case ERCOT Electric Reliability Council of Texas viii ETI Acronym for Entergy Texas, Inc. that is used in the administrative record—the same entity called “Entergy” in this brief FERC Federal Energy Regulatory Commission MSS-1 Schedule MSS-1 of the Entergy System Agreement, a tariff set by the Federal Energy Regulatory Commission MSS-2 Schedule MSS-2 of the Entergy System Agreement, a tariff set by the Federal Energy Regulatory Commission MSS-4 Schedule MSS-4 of the Entergy System Agreement, a tariff set by the Federal Energy Regulatory Commission Operating Companies Several Entergy related electric companies in Texas, Louisiana, Mississippi, and Arkansas that operate generation resources together under a System Agreement filed with the Federal Energy Regulatory Commission OPUC Office of Public Utility Counsel, created by statute to represent the interests of residential and small commercial customers in proceedings before the PUC Order The Commission’s order on rehearing that is the subject of this lawsuit. (AR, Item 244.) PFD Proposal for Decision prepared by the ALJ in this case (AR, Item 185.) Rate Base Another term for the utility’s invested capital used to determine how much a utility should receive in rates ix Rita Hurricane Rita that hit the upper Texas coast in 2005 Rita Asset The regulatory asset included in Entergy’s rate base that reflects Rita reconstruction costs that Entergy did not securitize because it incorrectly anticipated that they would be recovered through insurance proceeds. Securitization Order Tex. Pub. Util. Comm’n, Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No. 32907, available at http://interchange.puc.state.tx.us/WebApp/Interch ange/Documents/32907_401_532588.PDF (Dec. 1, 2006) (final order granting application) (Securitization Order). This is the docket where the Commission allowed Entergy to securitize Hurricane Rita reconstruction costs. Test year “The most recent 12 months for which operating data for an electric utility … are available and shall commence with a calendar quarter or a fiscal year quarter.” 16 Tex. Admin. Code § 25.5(134). TIEC Texas Industrial Energy Consumers, a group of industrial customers that participated as a party in this case x  Statement of the Case Entergy Texas, Inc., an electric utility in the southeastern part of Texas, together with several groups of its customers, filed administrative appeals of the Public Utility Commission’s order setting retail rates for Entergy. The district court affirmed the Commission’s order on all but one issue. In this brief, the Commission responds to appeals by Entergy and the Office of Public Utility Counsel on the other issues. Statement Regarding Oral Argument Based on the number of parties, the number of issues, and the complexity of rate regulation, oral argument would help the Court. xi  Issues Presented Issue 1: Did the Commission reasonably interpret how its prior ambiguous order in PUC Docket 37744 (the Black-box Order) treated the Hurricane Rita regulatory asset? (Responds to Entergy Issue 1) Issue 2: Does substantial evidence support the Commission’s decision to include Entergy’s 1997 ice-storm repair expenses when computing the utility’s insurance reserve? (Responds to OPUC Issue) Issue 3: Does substantial evidence support the Commission’s decision that Entergy failed to prove that certain purchased-power capacity costs were known-and-measurable changes to those expenses in the test year? (Responds to Entergy Issue 2) Issue 4: Does substantial evidence support the Commission’s decision that Entergy failed to prove that predicted transmission-equalization charges were known-and-measurable changes to those costs in the test year? (Responds to Entergy Issue 3) xii  Statement of Facts I. Procedural History This is an administrative appeal of a Public Utility Commission order that set retail electric rates for Entergy in PUC Docket 39896. The Commission continues to set retail electric rates for Entergy, which is situated outside the interconnected grid operated by the Electric Reliability Council of Texas (ERCOT), using traditional rate-setting procedures prescribed in Chapter 36 of the Utilities Code. Entergy initiated the rate case (SAR, ETI Exs. 1–6),1 and after notice was sent, many parties intervened. (AR, Item 185, Proposal for Decision (PFD) at 3, Binder 5.) Commission Staff also participated as a party, introducing evidence and presenting argument. (Id.) Administrative law judges (ALJs) conducted the hearing, and then the parties filed briefs with the ALJs. (AR, Items 152–155, 157–158, Binder 3; 159–162, 164, 167–175, Binder 4; 176–177, Binder 5.) The ALJs issued their 1 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 proposal for decision (AR, Item 185 (PFD)) that discussed the evidence and arguments and proposed findings of fact and conclusions of law. Parties filed exceptions to the PFD, and the case was sent to the Commission. (AR, Items 191–197, 200–206, Binder 6; AR, Items 207–208, Binder 7.) After considering the case in open meeting, the Commission issued its order (AR, Item 227, Binder 7), parties filed motions for rehearing (AR, Items 228–29, 231–42, Binder 7), and the Commission granted those motions in part and denied them in part in its order on rehearing (Order). (AR, Item 244, Binder 7.) The Order, the Commission’s final, appealable order, adopted much of the PFD. (AR, Order at 1.) Entergy, the utility, filed a suit for judicial review against the Commission. So did the following ratepayer groups: Cities, a group of cities in Entergy’s service area; OPUC; and State Agencies, certain Texas agencies that receive electric service from Entergy.2 The cases were consolidated, parties filed briefs, and the district court heard argument at its hearing on the merits. After considering the briefing of the parties, the administrative record, and the argument of the parties at the hearing on the merits, the district 2 Shortly before the hearing on the merits, State Agencies moved to withdraw their appeal, and the district court granted that motion. (C.R. 2079–83, 2084.) 2 court issued its judgment that affirmed the Commission on all but one issue. The Commission, Entergy, and OPUC filed notices of appeal, and have filed their appellants’ briefs. The Commission files this brief in response to the appellants’ briefs of Entergy and OPUC. II. Rate Setting Ratemaking is a legislative function. Pub. Util. Comm’n v. GTE-Sw., Inc., 901 S.W.2d. 401, 406 (Tex. 1995). The Commission exercises discretion when setting rates, which, pursuant to the Administrative Procedure Act, is done in a contested case. Tex. Gov’t Code § 2001.003(1). And the Public Utility Regulatory Act, (Tex. Util. Code §§ 11.01–66.016) (PURA), sets out the procedure for the Commission to set rates. First, the Commission decides how much revenue the utility needs to recover. This revenue requirement is the rate of return multiplied by the utility’s invested capital (rate base) plus the utility’s reasonable and necessary operating expenses: (rate base × rate of return) + expenses = revenue requirement. See Tex. Util. Code § 36.051. Next, the Commission must design the rates—determine how much should be collected from different rate classes and what method to use to collect those amounts. 3  So there are four main components to a Commission rate case: (1) the utility’s invested capital or rate base; (2) the reasonable rate of return the utility should earn on its invested capital; (3) the utility’s reasonable and necessary operating expenses; and (4) the rate design. In addition, fuel costs are recovered through temporary rates called “fuel factors.” In all components of a rate case, the burden of proof is on the utility. Tex. Util. Code § 36.006. The issues addressed in this brief concern both rate base and expenses. A. Rate Base Investments in physical assets are a large part of a utility’s rate base, but it also includes other assets: regulatory assets—expenses that the regulatory authority allows the utility to capitalize and recover over time by amortization—and a utility’s self-insurance storm-reserve account. 1. Hurricane Rita Regulatory Asset The issue about the Hurricane Rita regulatory asset (Rita Asset) traces back to Entergy’s costs of reconstruction after Hurricane Rita. Those costs were so great that the Legislature allowed utilities to recover them through securitization—selling bonds. Tex. Util. Code §§ 39.458–.463. 4  When the Commission authorized Entergy to securitize its Hurricane Rita reconstruction costs in PUC Docket 32907 (Securitization Order),3 the parties agreed on the amount of Hurricane Rita reconstruction costs, and Entergy estimated the amount of those costs it would receive through insurance proceeds. Securitization Order, FF 24 at 4–5. The amount securitized was reconstruction costs minus estimated insurance proceeds. Securitization Order, FF 35 at 7. The parties agreed to true up the amount of insurance proceeds later. Securitization Order, FF 29 at 5–6. Four years later Entergy realized that it would receive approximately $20 million less in insurance proceeds than it had anticipated, and asked the Commission in its 2010 rate case, the Black-box Case, to recover that $20 million with accrued interest as a regulatory asset. (AR, PFD at 16.) 2. Self-Insurance Storm Reserve and the 1997 Ice Storm The 1997 ice-storm issue concerns Entergy’s self-insurance plan. The Commission allows a utility to keep funds on hand to cover costs of natural disasters rather than paying a third party for insurance to cover those costs. The Commission’s rules provide that “a self insurance plan is a plan providing for accruals to be credited to reserve accounts.” 16 Tex. Admin. 3 Tex. Pub. Util. Comm’n, Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No. 32907, available at http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/32907_401_5325 88.PDF (Dec. 1, 2006) (final order granting application) (Securitization Order). 5 Code § 25.231 (b)(1)(G). The amount in a self-insurance account is deducted from rate base. 16 Tex. Admin. Code § 25.231(c)(2)(C)(iii). “The reserve accounts are to be charged with property and liability losses which occur, and which could not have been reasonably anticipated and included in operating and maintenance expenses, and are not paid or reimbursed by commercial insurance.” Id. Shortages in the reserve account increase the rate base and any surpluses in the reserve account are subtracted from rate base. 16 Tex. Admin. Code § 25.231(c)(2)(E). The Commission’s rules also require the utility to “maintain appropriate books and records to permit the commission to properly review all charges to the reserve account and determine whether the charges being booked to the reserve account are reasonable and correct.” Id. Due to an earlier statutory rate freeze and later settled rate cases, the Commission, for the first time in this case, addressed charges to Entergy’s storm-damage account based on several storm events, including reconstruction and repair costs after a severe ice storm in 1997. B. Reasonable and Necessary Expenses Entergy raises two issues about expenses: the cost of purchasing capacity and the cost of transmission services. In both, Entergy asked the Commission to increase the amount of expenses used to set rates from the 6 amount of those expenses in the test year, and in both, the Commission found that Entergy failed to meet its burden to prove that the post-test-year changes were known and measurable. Only reasonable-and-necessary expenses can be recovered in rates. Tex. Util. Code § 36.051. Although rates are set for the future, the expenses are based on the actual expenses the utility incurred in the test year. 16 Tex. Admin. Code § 25.231(b). The test year is “[t]he most recent 12 months for which operating data for an electric utility … are available and shall commence with a calendar quarter or a fiscal year quarter.” 16 Tex. Admin. Code § 25.5(134). The actual test-year expenses that are reasonable and necessary will only be adjusted for known-and-measurable changes. 16 Tex. Admin. Code § 25.231(b). Because the utility bears the burden of proof in a rate case (Tex. Util. Code § 36.006), Entergy had to convince the Commission that any post-test-year expenses it wanted to include in rates are known-and-measurable changes. Summary of the Argument The Commission’s Order should be affirmed. The Commission reasonably interpreted its prior rate-case order, the Black-box Order, to authorize Entergy to book and amortize a regulatory asset for unrecovered Hurricane Rita reconstruction costs. The Black-box Order was ambiguous 7 concerning the Rita Asset. That order was based on a “black box” settlement—one where only the amount of rates to be collected was set forth, not all of the individual components of a rate case. Because the Black-box Order did not explicitly state whether booking and amortizing the regulatory asset had been authorized, it was ambiguous. Courts defer to an agency’s interpretation of its prior, ambiguous order, and the evidence in the record supports the Commission’s decision. Substantial evidence supports the Commission’s decision that $13 million should be added to Entergy’s storm reserve based on the expenses Entergy incurred to repair equipment after a severe ice storm in 1997. A prior Commission decision that faulted Entergy for poor service quality did not amount to a finding that Entergy could not include the repair costs in the insurance reserve amount. Substantial evidence supports the Commission’s decision that Entergy failed to meet its burden of proof to increase the cost of purchasing capacity and the cost for transmission charges from the amount of those costs shown in the test-year amounts. The record supports the Commission’s decision that Entergy did not meet its burden of proving that requested changes were known and measurable. 8  For example, Entergy based its arguments about purchasing capacity on the assumption that it would always purchase the maximum amount under new contracts. Entergy claimed that it would have more customers in the future. Not only is that speculative, but the utility failed to account for how additional customers would otherwise affect its recovery through rates. And Entergy’s arguments about transmission charges are controlled by numerous unknown variables used in a complex formula. The Commission’s test-year rule is created to avoid just such unknowns. Moreover, most of Entergy’s request for post-test-year changes to transmission costs were based on an agreement that was still waiting for approval from the Federal Energy Regulatory Commission. That is patently not a “known” change. Because substantial evidence supports the Commission’s decisions, the Order should be affirmed. Argument I. Standard of Review As in any lawsuit, plaintiffs bear the burden of proof. For an administrative appeal of the Commission’s order in a contested case, those challenging the order must show reversible error; the substantial-evidence rule described in Section 2001.174 of the Administrative Procedure Act controls. See Anderson v. R.R. Comm’n, 963 S.W.2d 217, 219 (Tex. 9 App.—Austin 1998, pet. denied); Tex. Util. Code § 15.001; Tex. Gov’t Code § 2001.174. That rule is very deferential to the agency, but the deference owed varies depending on the type of error alleged. Issues raised by Entergy and OPUC invoke the substantial-evidence standard and the arbitrary-and-capricious standard. Substantial-evidence Standard When reviewing an agency’s fact finding, a court uses the deferential substantial-evidence standard. It prohibits a court from substituting its judgment for the agency’s as to the weight of evidence. Pub. Util. Comm’n v. Gulf States Utils. Co., 809 S.W.2d 201, 211 (Tex. 1991). “A court that is reviewing purely factual administrative findings … may determine only whether substantial evidence supports those findings.” Cities of Abilene v. Pub. Util. Comm’n, 146 S.W.3d 742, 748 (Tex. App.—Austin 2004, no pet.). The true test is not whether the agency reached the correct conclusion, but whether some reasonable basis exists in the record for the agency’s action. Tex. Health Facilities Comm’n v. Charter Med.-Dallas, Inc., 665 S.W.2d 446, 452 (Tex. 1984). “At its core, the substantial evidence rule is a reasonableness test or a rational basis test.” City of El Paso v. Pub. Util. Comm’n, 883 S.W.2d 179, 185 (Tex. 1994). 10  Arbitrary-and-capricious Standard The Texas Supreme Court has recognized the narrowness of the arbitrary-and-capricious standard of review when applied to agency decisions: “[W]e do not think that the legislature intended it to be interpreted as a broad, all-encompassing standard for reviewing the rationale of agency actions.” Charter Med., 665 S.W.2d at 454. Courts must uphold a Commission decision if “some reasonable basis exists in the record for the action taken by the agency.” City of El Paso, 883 S.W.2d at 185. II. The district court properly affirmed the Commission’s decision about the amount of the Hurricane Rita regulatory asset to include in Entergy’s rate base. (Responds to Entergy Issue 1) The district court properly affirmed the Commission’s determination of the amount of the Hurricane Rita regulatory asset (Rita Asset) that was in Entergy’s rate base when it set rates in this case. Substantial evidence supports the Commission’s reasonable decision that Entergy began amortizing that amount through rates set by the Black-box Order. In Entergy’s 2010 Black-box Case, the Commission allowed the utility to recover nearly $20 million of Rita recovery costs by creating and amortizing a regulatory asset. Considering the deference due to the Commission’s interpretation of its prior ambiguous order, this Court 11 should also affirm the Commission’s decision about the amount of the Rita Asset in rate base. A. Factual Background The Rita Asset was an issue in Entergy’s preceding rate case, the Black- box Case. As explained below, because that case was resolved based on the parties’ “black box” settlement, the Commission’s order in that earlier case is ambiguous as to how the Rita Asset was decided. The Commission’s Black-box Order4 contained little more detail than the total amount to be recovered in rates and the rate design used to recover that amount. In contrast, a typical Commission order adopting rates, like the order in this case, spells out in some detail the amounts in each category of invested capital (rate base)5 as well as the total rate base,6 each part of debt and return on equity used to determine the rate of return,7 the amounts of reasonable and necessary expenses in each category,8 and the 4 Tex. Pub. Util. Comm’n, Application of Entergy Texas for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744, available at http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/37744_1449_686 947.PDF (Dec. 13, 2010) (final order setting rates) (Black-box Order). A copy is attached as Appendix C. 5 AR, Order at Schedule III (invested capital). 6 Id. (showing $1,700,128,144 as the total invested capital). 7 AR, Order at 6–7, FF 64–71 at 18–19. 8 AR, Order at FF 72–170 at 19–29, Schedules II, IV, & V. 12 rate design listing each rate class and explaining how the rates to be paid by each class will be determined.9 But to reach a settlement in the Black-box Case, the parties omitted that detail. Finding of Fact 16 of the Black-box Order explained that the parties to that case agreed that Entergy “should be allowed to implement an initial overall increase in base-rate revenues of $59 million for usage on and after August 15, 2010.” Black-box Order, FF 16 at 15. And they agreed that Entergy “should be allowed to implement an additional overall increase in base-rate revenues of $9 million on an annualized basis effective for bills rendered on and after May 2, 2011.” Id. The lack of detail in the Black-box Order created an issue in the current rate case about how much of the Rita Asset was in Entergy’s current rate base. In this case, the parties disputed what part of the Rita Asset Entergy recovered under the Black-box Order. Entergy argued that it had not received any part of the Rita Asset from the Black-box Order, but in the alternative argued that only part of the Rita Asset had been recovered under the Black-box Order. (AR, Item 157 at 9-13, Binder 3.) Cities argued that the rates based on the Black-box Case settlement included amortization of the Rita Asset so that only a portion of that amount 9 AR, Order at FF 175–213 at 29–35. 13 remained to be recovered in this rate case. (AR, Item 161 at 10-12, Binder 4.) Commission Staff argued that Entergy had recovered all of the Rita Asset through the rates set in the Black-box Order, but in the alternative argued that only part of the Rita Asset had been recovered under the Black- box Order. (AR, Item 164 at 10, Binder 4; AR, Staff Ex. 1 (Givens Direct) at 32, Binder 40.) The ALJs decided that the Rita Asset had been partially amortized through the Black-box Case rates, but found that the amount recovered through those rates was different from the amounts proposed by any of the parties. (AR, PFD at 4.) The Commission adopted that part of the PFD. (AR, Order at 1.) B. Substantial evidence supports the Commission’s reasonable interpretation of its prior, ambiguous order. 1. The Black-box Order decided the Rita Asset issue. The Commission approved creation and amortization of the Rita Asset in the Black-box Order. All parties in the Black-box Case agreed that Entergy was entitled to recover the $20 million of overestimated insurance proceeds that it requested. And, by the terms of the Black-box Order, Entergy’s request that the Commission approve booking and amortizing the Rita Asset was either approved or denied in that case—it could not have 14 been ignored by the order. Thus, the Black-box Order had to have approved amortizing the Rita Asset. The PFD weighed several factors to determine what the Commission decided about the Rita Asset in the Black-box Case: • The Securitization Order said there would be a true up after the insurance proceeds were received. • Utilities Code Section 39.459(c) says if the timing of receiving insurance proceeds means that they were not included in securitization, they should be included in the next rate case. • The Black-box Case was the next rate case. • In the Black-box Case, no one objected to the regulatory asset or amortizing it. • The Black-box Order said that it resolved all issues except the Competitive Generation Services proposal. • The Black-box Order did not specifically exclude the Rita regulatory asset but did specifically exclude some other regulatory assets; some others were expressly approved. (AR, PFD at 20–21.) The last factor shows the ambiguity in the Black-box Order. All the other factors weighed in favor of holding that the 15 Commission approved booking and amortizing the Rita Asset in the Black- box Order. (Id.) Although the Commission relied on all of these considerations, Entergy attacks the factors individually. But as shown factor-by-factor below, Entergy’s arguments are unavailing. Securitization Docket As both the Commission and Entergy note, the Securitization Order said that there would be a true up after insurance proceeds were received. And all agree that once Entergy showed that it would not recover $20 million of the Rita reconstruction costs through estimated insurance proceeds, the Commission should take action to allow Entergy to recover those costs. That supports the idea that the Commission would act quickly—in the Black-box Case where it was first asked—to approve booking and amortizing the Rita Asset so that Entergy could quickly recover the overestimated insurance proceeds. The statute requires action in the next rate case. That the Black-box Case was the “next” base-rate case supports the Commission’s conclusion that it approved booking and amortizing the Rita Asset in that case. Entergy’s argument about which statute applies is irrelevant because all the cited statutes indicate that the utility should 16 recover its Rita reconstruction costs as soon as possible; as soon as Entergy raised the issue in a base-rate case. Both the statute cited by the Commission and that cited by Entergy emphasize the need to get funds to the utility quickly. Utilities Code § 39.459(c), cited by the Commission states: “If the timing of a utility’s receipt of [insurance proceeds] prevents their inclusion as a reduction to the hurricane reconstruction costs that are securitized, the commission shall take those amounts into account in (1) the utility’s next base rate proceeding; or (2) any proceeding in which the commission considers hurricane reconstruction costs.” Section 39.462(a) cited by Entergy stated that the utility is entitled to seek recovery “in its next base rate proceeding or through any other proceedings authorized by Subchapter C, Chapter 39.” And a stated purpose of the hurricane-recovery statutes is “to enable an electric utility subject to this subchapter to obtain timely recovery of hurricane reconstruction costs.” Tex. Util. Code § 39.458(a) (emphasis added). Thus, whichever statute applies, the Commission can reasonably expect to address insurance proceeds in the next base-rate case or other permitted Commission case. The Commission’s analysis is correct, whichever statute applies: the Commission should address questions about insurance proceeds for Rita 17 reconstruction costs when the utility raises the issue in a base-rate case. (Since both the Black-box Case and this case are base-rate proceedings, there is no need to address what other types of proceedings were available.) Which is the next rate case? The Black-box Case was the “next” base-rate proceeding. “[N]ext base rate proceeding” (Tex. Util. Code §§ 39.459(c) & .462(a)) refers to “the timing of a utility’s receipt of those amounts.” (Tex. Util. Code § 39.459(c)). The statute does not refer to the next proceeding after the Commission authorized securitization. Thus, the fact that Docket 34800 was Entergy’s next rate case10 after securitization did not make it the appropriate docket to address the $20 million of overestimated insurance proceeds. The Black-box Case was the first time Entergy asked to recover the Rita Asset. And the record indicates that the Black-box Case was the “next” Entergy rate case after the utility knew that it would not receive the anticipated $20 million of insurance proceeds. Entergy did not state exactly when it finally realized that it would not receive $20 million of anticipated insurance proceeds. But factors indicate that the Black-box 10 Tex. Pub. Util. Comm’n, Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800, available at http://interchange.puc.state.tx.us/WebApp/Interchange/application/dbapps/filings/pg Control.asp?TXT_UTILITY_TYPE=A&TXT_CNTRL_NO=34800&TXT_ITEM_MATC H=1&TXT_ITEM_NO=&TXT_N_UTILITY=&TXT_N_FILE_PARTY=&TXT_DOC_TY PE=ALL&TXT_D_FROM=&TXT_D_TO=&TXT_NEW=true (Sep. 26, 2007). 18 Case was the next proceeding: 1) Entergy was to make the adjustment in the next proceeding after that determination and 2) it would be in Entergy’s interest to begin receiving additional rates to compensate for those costs. This supports a reasonable inference that the Black-box Case—the docket where Entergy first asked for the $20 million—was the “next proceeding” after the utility knew that it would not receive those anticipated insurance proceeds. No objection to the regulatory asset or amortizing it Entergy asked for the Rita regulatory asset in the Black-box Case and no one in that case argued that Entergy was not entitled to recover that amount through rates. That is another factor that supports the Commission’s conclusion that booking and amortizing the Rita Asset was approved in the Black-box Order. The evidence in this case shows that no party to the Black-box Case disputed that the $20 million needed to be included in rates. In this case, PUC Staff Witness Givens testified that, other than a minor adjustment to the amount that he recommended, “No other adjustments were recommended to the Company’s request for inclusion of the regulatory asset in rate base or the amortization expense associated with the asset.” 19 (AR, Staff Ex. 1 (Givens Direct) at 33,11 Binder 40.) And Cities witness Garrett testified: “[E]ven though the last rate case settled, since no party opposed the Company’s inclusion in rates of the Rita regulatory costs, the Company should have been amortizing the Rita regulatory balance since the last case, … .” (AR, Cities Ex. 2 (Garrett Direct) at 11, Binder 8.) Based on that testimony, the Commission, in this case, decided that in the Black-box Case “there was no objection to [Entergy]’s proposed Hurricane Rita regulatory asset, it was authorized by the prior settlement in [the Securitization Order docket], and the Commission was directed by PURA § 39.459(c) to take into account [Entergy]’s insurance proceeds related to the Hurricane Rita securitized costs in [Entergy]’s next rate case, which was [the Black-box Case].” (AR, PFD at 21–22.) All issues resolved in the Black-box Order The Black-box Order states that the parties entered into “a stipulation and settlement agreement that resolves all of the issues in this proceeding except the issues related to [Entergy]’s proposal for competitive generation service.” Black-box Order at 1 (emphasis added). No parties to this case dispute that “[i]n [the Black-box Case], [Entergy] requested recovery of the 11 Several exhibits in the Administrative Record have multiple page numbers. Citations are to the Bates stamped number on the bottom right of the exhibit unless there is no such number on the page. 20 Overestimated Insurance Proceeds by establishing a regulatory asset of $19,686,096, plus accrued carrying costs, to be amortized over five years.” (AR, PFD at 16). And Ordering Paragraph 15 in the Black-box Order states: “All other motions, requests for entry of specific findings of fact, conclusions of law, and ordering paragraphs, and any other requests for general or specific relief, if not expressly granted in this order, are hereby denied.” Thus, if the Commission did not address the Rita Asset in that PUC docket, the Commission denied Entergy’s request. Entergy’s attempt to argue that the Commission approved the Rita Asset but did not order the utility to begin recovering it through amortization is unavailing. As explained above, evidence in this case shows that Entergy requested both in the Black-box Case. And, the utility fails to explain how only one part of its request could have been approved given the language of the Black-box Order. In this rate case, Entergy bears the burden to prove how much of the Rita Asset is in rate base. The Utilities Code places the burden of proof in a rate case on the utility. Tex. Util. Code § 36.006. Rate base (also called invested capital) is one of the inputs to determine the utility’s revenue requirement. Thus, the utility bears the burden to prove the amount of its rate base. See Cities of Abilene v. Pub. Util. Comm’n, 854 S.W.2d 932, 21 936–37 (Tex. App.—Austin 1993) (recognizing the utility’s burden of proof and that determining rate base is one of the three factors used to determine a utility’s rates), aff’d in part, rev’d in part on other grounds, 909 S.W. 2d 493 (Tex. 1995). This Court recently recognized the utility’s burden to prove the amount in its rate base when the Court cited the prudence standard used to determine whether assets purchased by a utility should be included in rate base. See State Agencies & Insts. of Higher Learning v. Pub. Util. Comm’n, 450 S.W.3d 615, 635 (Tex. App.—Austin 2014, pet. filed) (applying the prudence standard to Oncor Electric Delivery Company’s purchase of smart meters). And in Entergy Gulf States, Inc. v. Pub. Util. Comm’n, 112 S.W.3d 208 (Tex. App.—Austin 2003, pet. denied), the entire case is about the utility’s burden to prove the amount of its rate base. Because the Rita-Asset question concerns how much is included in Entergy’s rate base, Entergy bore the burden of proving that amount. 2. The Court should defer to the Commission’s interpretation of its ambiguous Black-box Order. A court generally defers to an agency’s interpretation of its prior order. “Just as we give great weight to an agency’s interpretation of its own rules and regulations, we give great weight to an agency’s interpretation of its administrative orders.” AEP Tex. N. Co. v. Pub. Util. Comm’n, 297 22 S.W.3d 435, 447 (Tex. App.—Austin 2009, pet. denied). “If the Settlement Order is ambiguous, we will affirm the Commission’s interpretation of it in the Final Order if the interpretation is supported by substantial evidence.” Cities of Abilene v. Pub. Util. Comm’n, 146 S.W.3d at 748. The Court should defer to the Commission’s reasonable interpretation of its prior, ambiguous order. III. The Commission properly included the 1997 ice-storm recovery costs in the storm-damage reserve account. (Responds to OPUC Issue) Substantial evidence shows that the expenses for the 1997 ice-storm recovery belong in Entergy’s self-insurance storm-reserve account. A. Background of the storm-reserve account. In this case, Entergy showed that it had overdrawn its storm-reserve account. In PUC Docket 16705 and in the Black-box Order, Entergy was allowed to maintain a storm damage reserve of about $15.6 million.12 (AR, PFD at 45.) But over the course of the 15 years prior to this case, more than 200 storms occurred. (Id.) So Entergy had charged about $101.7 million to the reserve account in costs of restoring service (not counting securitized 12 Tex. Pub. Util. Comm’n, Application of Entergy Texas for Approval of its Transition To Competition Plan and the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to Recover a Surcharge for Under-Recovered Fuel Costs, Docket No. 16705 available at http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/98171.TIF (Oct. 14, 1998) (second order on rehearing at FOF 120). 23 expenses). At the same time, Entergy had accrued only about $29.8 million in its reserve. (Id.) Thus, in this case, Entergy asked the Commission to agree that the current amount of its storm-reserve account was about a negative $59.8 million. (Id.) The Commission agreed (AR, Order, FF 50) and ordered the reserve to be replenished in increments, eventually establishing a $17.6 million storm-reserve account. (AR, Order, FF 157-159.) The $13 million of 1997 ice-storm costs that OPUC complains about is included in the $59.8 million negative storm reserve. B. The Commission did not decide in earlier dockets whether the 1997 ice-storm expenses were properly charged against the storm-reserve account. Although there were several Entergy rate cases before this case, none of them determined whether expenses were properly charged against the storm-reserve account. In fact, the Commission did not have the opportunity to consider whether the 1997 ice-storm expenses were properly charged against the storm-reserve account until this 2012 rate case. No party disputes that the Commission carried the question whether the 1997 ice-storm repair expenses were properly booked against Entergy’s storm-reserve account for over a decade. In October 1998, the Commission ordered Entergy to prove the reasonableness and prudence of charging the 24 ice-storm expenditures against the storm-reserve account in its next (November 1998) rate case. But that rate case settled in June 1999 without addressing the 1997 ice-storm expenditures.13 Entergy’s next rate case was dismissed by the Commission in October 2004 because of a statutory rate freeze.14 A March 2009 rate case settled without specifically addressing the ice-storm expenditures, and the Black-box Case settled in December 2010 without addressing the expenditures. Accordingly, 15 years after the original storm, the Commission considered the ice storm expenditures in this case. C. The reasonableness and prudence of the 1997 ice- storm expenses was based on the evidence in this case; it was not decided in Docket No. 18249. OPUC’s reliance on the Service-quality Order is misplaced because it is based on an incorrect premise. Both here and at the Commission OPUC claimed that the Commission had decided that the expenses for the 1997 Ice Storm were imprudently incurred in PUC Docket No. 18249 (the 13 Tex. Pub. Util. Comm’n, Application of Entergy Gulf States, Inc. for Authority to Change Rates, Docket 20150, available at http://interchange.puc.state.tx.us/WebApp/Interchange/application/dbapps/filings/pg Search_Results.asp?TXT_CNTR_NO=20150&TXT_ITEM_NO=717 (Jun. 30, 1999) (20150 Order). 14 Tex. Pub. Util. Comm’n, Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket 30123, available at http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/30123_112_4593 36.PDF (Oct. 20, 2004) (30123 Order). 25 Service-quality Order).15 So OPUC did not present evidence of any imprudence in this case. The Commission’s severed the service-quality case out of a 1996 rate case so that the Commission could address the quality of Entergy’s electric service to its customers after a merger in 1993. (Service-quality Order, at 39.) In the Service-quality Order, the Commission addressed maintenance policies, Entergy’s level of spending in the area of operations and maintenance, the experience of its personnel, and the consequent quality of its service. (Id. at 7.) In that 1998 decision, the Commission stated that “[t]he January 1997 ice storm was certainly a severe storm that would have adversely affected even the best-maintained distribution system” (Id. at 18; PFD at p. 56), but the agency also determined that Entergy’s poor service quality and vegetation management failures aggravated the situation. (Id. at 18-19.) In response to all the poor service-quality issues shown, the Commission (1) reduced Entergy’s return on equity by 60 basis points, (2) required Entergy to make refunds to its customers, and (3) imposed significant spending requirements and quantified performance guarantees. (Id. at 51-53.) 15 Tex. Pub. Util. Comm’n, Entergy Gulf States, Inc. Service Quality Issues (Severed From Docket 16705), Docket 18249, available at http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/18249_109_5520 77.PDF (Apr. 22, 1998) (order on rehearing) (the Service-quality Order). 26  In this case, the 1997 ice-storm issue was not about the general level of service provided by Entergy in 1996 but whether the utility proved the $13 million it spent for repairs after the ice storm was properly charged against the storm-reserve account. The PFD states that Entergy established that the expenses it incurred to repair damage and restore service after the ice storm “were reasonable and necessary, and the ALJs find that they should be included in the storm damage reserve.” (AR, PFD at 57.) Thus, the Commission found that the statements in its 1998 order were not enough to overcome Entergy’s showing that the actual expenditures were reasonable, necessary, and prudent. D. Substantial evidence supports the expenses of restoring service after the 1997 Ice Storm. Substantial evidence supports the determination that the expenses Entergy incurred to restore power after the ice storm were reasonable, necessary, and prudent. Entergy Witness Shawn Corkran testified that he reviewed the expenses and “determined that the costs were reasonable and necessary to reliably restore service to customers as quickly as possible after the ice storm.” (AR, ETI Ex. 48 (Corkran Rebuttal) at 10, Binder 37, Ex. SBC-R-1, at 22.) Entergy backed up this testimony with exhibits containing a breakdown of expenses for labor, materials, transportation, lodging, and other expenses. (Id.) “[O]nce the ice storm occurred, 27 [Entergy] had to take appropriate action to repair the damage and restore service.” (AR, PFD at 57.) Substantial evidence also supports the determination that the expenses were not reasonably anticipated. Entergy’s Corkran provided 11 pages of testimony backed by exhibits providing a detailed breakdown of the expenses incurred to take appropriate action to repair the damage and restore service once the storm occurred. (AR, ETI Ex. 48 (Corkran Rebuttal) at 4–14, Binder 37, and Ex. SBC-R-1, at 22.) Corkran established that the ice storm was the most destructive winter storm to ever hit the Entergy system. (Id. at 7.) The storm de-energized approximately 3,400 miles of distribution lines and 560 miles of transmission lines. (Id.) The affected service area was within the light ice-loading zone according to the National Electric Safety Code (“NESC”) in effect at the time, (id. at 9) and the light ice-loading zone is defined by no ice accumulation on the distribution lines. (Id.) The majority of the damage at issue was caused by an accumulation of one to three inches of ice while temperatures remained below freezing for more than two days after the storm’s initial onset. (Id.) Corkran testified that although Entergy generally exceeds NESC strength requirements, the ice storm put an extraordinary burden on the facilities, causing the wires, poles, and other equipment to collapse from 28 the weight of the accumulated ice, and causing tree limbs weighed down by ice accumulation to fall on Entergy’s lines. (Id.) Thus, the severe impact of the ice storm was not reasonably anticipated in the NESC or by Entergy. In conclusion, Corkran stated that the ice storm restoration and recovery expenses were “reasonable, necessary and prudently incurred.” (Id. at 13- 14.) OPUC’s complaint that Entergy failed to identify and quantify which of its expenses were imprudent is unavailing. Entergy claimed all its expenses were reasonable, and a utility is not required to identify which expenses are imprudent. Tex. Utils. Elec. Co. v. Pub. Util. Comm’n, 881 S.W.2d 387, 404 (Tex. App.—Austin 1994) (“Nowhere does the supreme court state that a utility must segregate imprudent costs.”), aff’d in part, rev’d in part on other grounds, 935 S.W.2d 109 (Tex. 1997). E. OPUC’s additional complaints do not show error. OPUC’s further complaints are without merit. OPUC has not shown that the Commission’s decision is arbitrary and capricious despite being supported by substantial evidence. The Commission was not required to make an ultimate finding of fact in statutory language that storm-reserve expenses were “not reasonably anticipated” as OPUC contends. Neither the Commission’s rule nor the 29 Utilities Code require such a finding of fact. See 16 Tex. Admin. Code § 25.231(b)(1)(G); Tex. Util. Code § 36.064(a). And, as stated above, the Commission’s findings in the PFD show the Commission considered that it would not have been reasonable to anticipate the devastation caused by the 1997 Ice Storm. An ultimate finding of fact in statutory language is not required if the findings reflect that the Commission considered the required underlying criteria. See Meier Infiniti v. Motor Vehicle Bd. 918 S.W.2d 95, 100-01 (Tex. App.—Austin 1996, writ denied). Moreover, the Commission did not consider an irrelevant factor when it decided to include the 1997 ice-storm recovery costs in the storm reserve. OPUC’s assertion that the Commission improperly considered the passage of time and “absolved the Company of its burden to prove” its expenditures were imprudent is unfounded. (OPUC Appellant’s Brief at 38.) This is merely a continuation of OPUC’s incorrect assertion that the utility must identify its imprudence. OPUC’s requested relief should be denied. 30 IV. Substantial evidence supports the Commission’s determination that Entergy failed to meet its burden to prove that predicted purchased-power capacity costs were known-and-measurable changes to the test-year data. (Responds to Entergy’s Issue 2). Substantial evidence supports the Commission’s determination that Entergy failed to meet its burden to prove that certain projected costs for purchasing capacity were known-and-measurable changes from the costs incurred during the test year. Some contracts Entergy relied upon were not yet in place, and inputs for the variables in formulas for Entergy’s contracts with its affiliates were unknown. Thus, the Commission determined that Entergy failed meet its burden. The district court properly affirmed this determination, and its judgment should be upheld. A. The Commission uses the utility’s actual expenses during a test year to determine what expenses to include in rates, and they can only be changed for known-and-measurable changes. The Commission’s rules require the expenses included in rates to be based on the utility’s actual expenses during a test year that ends before the utility applies to change rates. And only expenses that are reasonable and necessary can be recovered. Tex. Util. Code § 36.051. Although rates are set for the future, “[i]n computing an electric utility’s allowable expenses, only the electric utility’s historical test year expenses as adjusted for known and measurable changes will be considered, … .” 16 Tex. Admin. Code 31 § 25.231(b). The test year is “[t]he most recent 12 months for which operating data for an electric utility, electric cooperative, or municipally- owned utility are available and shall commence with a calendar quarter or a fiscal year quarter.” 16 Tex. Admin. Code § 25.5(134). Because the utility bears the burden of proof in a rate case (Tex. Util. Code § 36.006), that includes the burden to prove that the post-test-year, purchased-power agreements are known-and-measurable changes. Courts have recognized the Commission’s broad discretion over deciding whether to allow post-test-year adjustments. “[T]he Commission’s authority to allow post-test-year adjustments for ‘known and measurable changes to historical test-year data’ is discretionary.” Cent. Power & Light v. Pub. Util. Comm’n, 36 S.W.3d 547, 563 (Tex. App.—Austin 2000, pet. denied); see also Cities of Corpus Christi v. Pub. Util. Comm’n, No. 03-06-00585-CV, 2008 WL 615417 (Tex. App.—Austin Mar. 5, 2008, no pet.) (mem. op.) (“The Commission may decide in its discretion whether to incorporate ‘known and measurable’ changes to the test-year data.”) (citing Office of Pub. Util. Counsel v. Pub. Util. Comm’n, 185 S.W.3d 555, 566 n.14 (Tex. App.—Austin 2006, pet. denied); 16 Tex. Admin. Code § 25.231(a)). 32  B. Entergy sought adjustments outside the test year for alleged future capacity expenses. Entergy sought adjustments for the capacity costs it alleged would be incurred outside the test year. Capacity costs, generally, are those “costs associated with providing the capability to deliver energy (primarily the capital costs of facilities).” Gulf States Utils. Co. v. Pub. Util. Comm’n, 841 S.W.2d 459, 461 (Tex. App.—Austin 1992, writ denied). “‘Capacity costs’ refers to one element of the price charged by a seller of electric power—an element that represents the seller’s fixed costs in generating the power.” City of El Paso v. El Paso Elec. Co., 851 S.W.2d 896, 898 (Tex. App.—Austin 1993, writ denied). These costs, unlike fuel expenses, are generally recovered through base rates. See City of El Paso v. Pub. Util. Comm’n, 344 S.W.3d 609, 614 (Tex. App.—Austin 2011, no pet.). In this case, during the test year, Entergy had purchased-power capacity costs of $245.4 million. But Entergy sought to recover an additional $31 million based upon what it believed would be the purchased- power agreements in place during the “rate year,” the first year of new rates set by the case. Commission Staff and several intervenors opposed Entergy’s request to recover the additional $31 million and offered testimony and argument against Entergy’s proposed adjustment. 33  Staff and intervenors pointed out several problems with Entergy’s proposed post-test-year adjustments, arguing that these additional costs are mere projections. For example, Entergy relied on projections, rather than known actual payments, when estimating what it would pay under third-party contracts in the future. Indeed, many of the contracts do not contain fixed-price terms, and Entergy’s costs will fluctuate based on factors such as required availability and performance. (PFD at 101-02 (citing AR, Tr. at 704-05).) Nevertheless, Entergy “simply assumed it would pay the maximum amount possible under each of its third party contracts, and disregarded any of the contractual factors that might reduce its Rate Year payments.” (AR, PFD at 102 (citing AR, Tr. at 704-05).) Likewise, the expenses requested under Entergy’s contractual agreements with its affiliates rest on several assumptions. The contracts do not definitively fix prices or quantities, which will fluctuate based on the specific operational conditions experienced in the future. (AR, PFD at 102 (citing AR, Tr. at 606).) The ultimate determination of payments will be based on a formula set out in a Federal Energy Regulatory Commission tariff, schedule MSS-4. Entergy could not know what variables should be inserted in that formula. Instead, to project its costs, Entergy made assumptions about each of the several variables contained in the formula. 34 (Id.) Intervenors argued that this was too speculative to constitute a known and measurable change. To illustrate their position that Entergy’s proposed costs were inherently speculative, the intervenors pointed to a new Entergy contract (the EA WBL Contract). That contract, which was executed only days before the SOAH hearing, accounted for more than a third of Entergy’s proposed $31 million increase in expenses. Not only would pricing under the contract be determined pursuant to the complex formula in MSS-4, but also how much capacity Entergy ultimately purchased would be based on an allocation percentage between Entergy and other companies that had not yet been determined. Moreover, the contract itself might never go into effect because it is subject to Entergy receiving regulatory approval from the Federal Energy Regulatory Commission. Even if the contract became effective in the future, it would still be subject to at least two further revisions before any power could be received under the contract. (AR, PFD at 102-03 (citing AR, ETI Ex. 47 (Cooper Rebuttal) at RRC-R-1, Binder 37, and AR, Tr. at 628-29).) Changes Entergy proposed based on estimated payments under another FERC tariff, the MSS-1, also required several assumptions about the future. To calculate its obligations under MSS-1, Entergy had to 35 forecast not only its own future loads, but the future loads of all the other Operating Companies16 in the Entergy family of companies. If those assumptions regarding future loads are incorrect, Entergy’s projected costs could be significantly different. (AR, PFD at 103 (citing AR, Tr. at 651–52).) The intervenors pointed out the inconsistency in Entergy’s position on the measurability of future load growth, noting that elsewhere in the case, Entergy took the position that future projected loads should not be considered known and measurable. (AR, PFD at 103 (citing AR, Tr. at 1907; see also AR, Item 164 at 28, Binder 4; AR, Item 159 at 27-28, Binder 4.) (emphasis added).) The ALJs also noted the following testimony of Entergy Witness Phillip May regarding the certainty of Entergy’s MSS-1 projections: Q: Do you think that the projection . . . of rate year sales that is implicit in the calculation of MSS-1 costs . . . is a known and measurable change? A: I think there is some uncertainty with regard to that projection, yes, sir. (AR, PFD at 103-04 (citing AR, Tr. at 1918-19).) The intervenors also argued that it was inappropriate to impose the future costs of securing capacity to serve a larger, future load on existing 16 Entergy is one of several related electric companies in Texas, Louisiana, Arkansas, and Mississippi. Those are called “operating companies” in this case. 36 customers without taking into account increased customer growth and sales revenue. The result, they argued, would violate the “matching principle” whereby “the attendant impacts on all aspects of a utility’s operations (including revenue, expenses, and invested capital) can with reasonable certainty be identified, quantified, and matched.” (AR, PFD at 104 (citing AR, Cities Ex. 6 (Nalepa Direct) at 12, Binder 9, citing 16 Tex. Admin. Code § 25.231(c)(2)(F)(i)(IV).) “The argument, essentially, is that the various new or expanded contracts that [Entergy] has entered into were executed so that, in whole or part, [Entergy] would be able to meet future demand, but that [Entergy] is seeking to recover the costs of those new contracts from its existing customers.” (AR, PFD at 104 (citing AR, Cities Ex. 6 (Nalepa Direct) at 11, Binder 9; see also AR, Item 161 at 38, Binder 4; AR, Item 164 at 30, Binder 4; AR, Item 159 at 35-39, Binder 4.).) C. Entergy failed to prove that the adjustments were known-and-measurable changes. Weighing all the evidence, the ALJs “conclude[d] that [Entergy] failed to meet its burden to prove that the adjustment it seeks to its Test year [Purchase Power Capacity Contracts] is known and measurable.” (AR, PFD at 108.) And the ALJs found that the intervenors had “presented substantial evidence that all of the components of [Entergy]’s purchased 37 power capacity contain significant variability and uncertainty in costs.” AR, PFD at 109.) The Commission agreed.17 It denied Entergy’s request for post-test- year costs, as set out in Findings of Fact 72 through 86. (AR, Order, FF 72–86.) In its briefing, Entergy cites particular provisions of various contracts and argues that it was unreasonable for the Commission to deny all of the proposed expenses. But Entergy bore the burden to prove that these adjustments were known and measurable. Both because whether to allow post-test-year adjustments is within the Commission’s discretion, and because these findings are supported by substantial evidence, Entergy’s complaint should be rejected. V. Substantial evidence supports the Commission’s determination that Entergy failed to meet its burden to prove that predicted transmission-equalization charges were known-and-measurable changes to the test-year data. (Responsive to Entergy’s Issue 3). As with the purchased-power capacity costs, substantial evidence supports the Commission’s determination that Entergy failed to meet its burden to prove that transmission-equalization expenses that the utility alleged it would incur outside the test year were known and measurable. 17 However, after Entergy pointed to an additional $522,002 of purchased power capacity costs incurred during the test year, the Commission modified the ALJs’ proposal to allow for a total recovery of $245,965,886. 38  A. Entergy recovers transmission equalization expenses through rates. The Entergy-system transmission grid is a large, integrated network that is operated for the mutual benefit of all of the Entergy Operating Companies. The costs of operating this system are allocated among the Operating Companies pursuant to Service Schedule MSS-2, a FERC tariff, under which each Operating Company contributes its just and reasonable share of the costs. Those costs are referred to as “transmission equalization” payments, and Entergy recovers them as expenses in rates. As the ALJs explained, “In any given month, some of the Operating Companies might be ‘long’ on the amount of transmission capacity they own (meaning that they own more capacity than they need) while others might be ‘short’ on capacity (meaning they own less capacity than they need). In such a month, the long Operating Companies would receive MSS-2 payments from the short Operating Companies for use of their transmission facilities.” (AR, PFD at 110 (citing AR, Tr. at 731, 735).) B. Entergy sought an adjustment based on anticipated post-test-year transmission expenses. Entergy sought to recover $9 million more for transmission expenses that it incurred in its test year. During the test year, Entergy was short and paid more than $1.7 million in MSS-2 payments to other Operating 39 Companies. (AR, PFD at 110 (citing AR, Tr. at 723-24, 737; AR, Cities Ex. 28 (ETI response to Cities RFI 3-3), Binder 9.).) Entergy does not dispute that this $1.7 million represents its total transmission-equalization costs incurred during the test year. But, Entergy asked for post-test-year adjustments based on its estimates of transmission construction projects expected to be completed after the test year. These projects would result in changes to the relative transmission-line-ownership ratios among the Operating Companies, with the apparent result that Entergy would be increasingly short and its payments under MSS-2 would grow. Commission Staff and other parties opposed including these post- test-year expenses, arguing that they were not sufficiently known or measurable to include in rates set in this case. Payments under MSS-2 are calculated using a complex mathematical formula involving many variables, such as the amount of investments in transmission facilities made by each Operating Company, the costs of capital for each Operating Company, the size of the load demanded by each Operating Company, and the amount of state and federal tax paid by each Operating Company. Changes in any of these variables would change the amount Entergy would owe—or be due—under the formula. (AR, PFD at 111 (citing AR, ETI Ex. 39 (Cicio Direct) at PJC-1 at 38-43, Binder 36; AR, Tr. at 454-55.).) TIEC 40 Witness Pollock testified that any attempt to estimate these many variables “is susceptible to a host of uncertainties.” (AR, TIEC Ex. 1 (Pollock Direct) at 29, Binder 41.) Aside from the difficulties involved in estimating several variables for several companies, the transmission projects involved had not yet come into service and were still in the planning or construction phase. Entergy acknowledged that if the projects were not completed on schedule, then its projected MSS-2 costs would be inaccurate. (AR, PFD at 112 (citing AR, Tr. at 800-801).) TIEC argued that it would be bad policy for the Commission to rely on “speculative construction end dates to form the basis of a known and measurable change to test year costs.” (AR, PFD at 113 (citing AR, Item 159 at 47, Binder 4).) The intervenors argued that Entergy had offered scant evidentiary support for some of its estimates, and contended that it would be unfair to allow Entergy to immediately begin recovery of MSS-2 payments that would not be incurred for many months. (AR, PFD at 113.) Cities pointed out an additional uncertainty: Entergy and the various Operating Companies had announced a plan to sell all of their transmission assets to a third party. If that transaction took place, it would be impossible to know what transmission equalization expenses—if 41 any—Entergy would incur. (AR, PFD at 113 n.370 (citing AR, Item 171 at 67-68, Binder 4; AR, Tr. at 113-14; AR, Cities Ex. 4 (Goins Direct) at 20-21, Binder 8).) In addition, TIEC noted that there are cost-recovery mechanisms available in the event that Entergy’s rate-year costs deviate substantially from its test-year costs.18 Therefore, Entergy’s proposed post- test-year transmission costs were unnecessary. C. Entergy failed to meet its burden, and the Commission denied its requested adjustments. Entergy did not convince the ALJs that the utility’s proposed expenses were known-and-measurable changes to the test-year expenses. The ALJs concluded “that [Entergy] failed to meet its burden to prove that its proposed Rate Year MSS-2 costs are known and measurable.” (AR, PFD at 116.) The ALJs noted that the MSS-2 formula requires assumptions about a great number of variables. “Changes to any of the variables could occur during the Rate Year, thereby altering the amount paid by (or received by) [Entergy] during the Rate Year.” (Id.) Moreover, “projects that underlie [Entergy]’s Rate Year request are largely not yet built, and might never be built.” (Id.) And estimates provided by different parties 18 Specifically, a Transmission Cost Recovery Factor under 16 Tex. Admin. Code §25.239(c) could allow the utility to “recover its reasonable and necessary costs for transmission infrastructure improvement and changes in wholesale transmission charges to the electric utility under a tariff approved by a federal regulatory authority to the extent that the costs or charges have not otherwise been recovered.” 42 varied widely. That “illustrat[ed] the problem of deviating from actual Test year data in an area that involves so many future contingencies and unknowns.” (Id.) And the ALJs were persuaded by the intervenors’ evidence which demonstrated that Entergy’s estimate of its rate-year MSS-2 costs are not known and measurable. (Id.) The Commission agreed that Entergy had not met its burden to demonstrate its estimated expenses were known and measurable and determined that Entergy’s recoverable expenses should be limited to those incurred during the test year. (AR, Order, FF 87-94.) Substantial evidence supports these findings, and Entergy’s complaint should be overruled. Prayer The Commission asks the Court to affirm the district court’s judgment on the issues raised by Entergy and OPUC, but to reverse the district court’s judgment to the extent that it found error in 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 43 CHARLES E. ROY First Assistant Attorney General 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 Douglas B. Fraser Assistant Attorney General State Bar No. 07393200 doug.fraser@texasattorneygeneral.gov Daniel C. Wiseman Assistant Attorney General State Bar No. 24042178 daniel.wiseman@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 44  Certificate of Compliance I certify that the foregoing computer-generated document has 9144 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 45  Certificate of Service I hereby certify that on this the 30th day of April 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 46 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 47 APPENDIX A  r.' ,.... ......... : ,_, - '-: T) PUC DOCKET NO. 39896 2012 NOV -2 M1 9: 24 SOAH DOCKET NO APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION INC. FOR AUTHORITY TO CHANGE § RATES, RECONCILE FUEL COSTS, § OF TEXAS AND OBTAIN DEFERRED § ACCOUNTING TREATMENT § ORDER ON REHEARING This Order addresses the application of Entergy Texas, Inc. for authority to change rates, reconcile fuel costs, and defer costs for the transition to the Midwest Independent System Operator (MISO). In its application, Entergy requested approval of an increase in annual base- rate revenues of approximately $111.8 million (later lowered to $104.8 million), proposed tariff schedules, including new riders to recover costs related to purchased-power capacity and renewable-energy credit requirements, requested final reconciliation of its fuel costs, and requested waivers to the rate-filing package requirements. On July 6, 2012, the State Office of Administrative Hearings (SOAH) administrative law judges (ALJs) issued a proposal for decision in which they recommended an overall rate increase for Entergy of $28.3 million resulting in a total revenue requirement of approximately $781 million. The ALJs also recommended approving total fuel costs of approximately $1.3 billion. The ALJs did not recommend approving the renewable-energy credit rider and the Commission earlier removed the purchased-power capacity rider as an issue to be addressed in this docket. 1 On August 8, 2012, the ALJs filed corrections to the proposal for decision based on the exceptions and replies of the parties.2 Except as discussed in this Order, the Commission adopts the proposal for decision, as corrected, including findings of fact and conclusions of law. Parties filed motions for rehearing on September 25 and October 4, 2012 and filed replies to the motions for rehearing on October I 5, 2012. The Commission considered the motions for 1 Supplemental Preliminary Order at 2. 3 (Jan. 19, 2012). 2 Letter from SOAHjudges to PUC (Aug. 8, 20 12). PUC Docket No. 39896 Order on Rehearing Page 2 of 44 SOAH Docket No. rehearing at the October 25, 2012 open meeting. The Commission granted Commission Staffs motion for rehearing that requested technical corrections to reflect the rates that resulted from the Commission Staff number-running memo that was filed on August 28, 2012. The Commission modifies findings of fact 205, 206, 208, and 210 as requested by Commission Staff and attaches Commission schedules I through V to reflects its decisions. The Commission granted the Department of Energy's motion for rehearing requesting that finding of fact 198 be modified to reflect the applicable off-season for the schedulable intermittent pwnping service. Finding of fact 198 is modified to reflect that the off-season is October through May. In its motion for rehearing, Entergy noted that findings of fact 178 and 170 should be modified to more accurately reflect the procedural history. The Commission modifies findings of fact 178 and 170 to state that Entergy agreed to extend time to provide the Commission sufficient time to consider the issues in this proceeding on two occasions-at the July 27 and August 30, 2012 open meetings. I. Discussion A. Prepaid Pension Asset Balance Entergy included in rate base an approximately $56 million item named Unfunded Pension. 3 This amount represents. the accumulated difference between the annual pension costs calculated in accordance with the Statement of Financial Accounting Standards (SF AS) No. 87 and the actual contributions made by Entergy to the pension fund-Entergy contributed nearly $56 million more to its pension fund than the minimum required by SFAS No. 87. 4 In Docket No. 33309, the Commission allowed a pension prepayment asset, excluding the portion of the asset that is capitalized to construction work in progress (CWIP), less accrued deferred federal income taxes (ADFIT) to be included in rate base. 5 For the excluded portion, the Commission allowed the accrual of an allowance for funds used during construction 3 Proposal for Decision at 23 (July 6. 201 2) (PFD). 4 PFD at 23-24. s Application of AEP Texas Central Company f or Authority to Change Rates, Docket No. 33 309, Order on Rehearing (March 4, 2008). PUC Docket No. 39896 Order on Rehearing Page J or 44 SOAH Docket N o . - 6 (AFUDC). The ALJs concluded that this approach was sound and should be followed in this 7 case. Thus, the ALJs recommended that the CWIP-related portion of Entergy's prepaid pension asset ($25,311,236) should be excluded from the asset and should accrue AFUDC.8 However. the ALJs did not address ADFIT. The Commission agrees that the CWIP-related portion of Entergy's pension asset should be excluded from the asset and that this excluded portion should accrue AFUDC . However, the Commi ssion also finds that the impact of this exclusion on Entergy 's ADFIT should be reflected. When items are excluded from rate base, the related ADFIT should also be excluded. The adjusted ADFIT for the prepaid pension asset remaining in Entergy's rate base should be reduced by $8,858,933, the deferred taxes related to the excluded $25 million. The Commission adds new finding of fact 28A to reflect this modification to Entergy's AD FIT. B. FIN 48 The Financial Accounting Standards Board's Interpretation No. 48 (FIN 48) prescribes the way in which a company must analyze, quantify, and disclose the potential consequences of tax positions that the company has taken that are legally uncertain. Entergy reported that its uncertain tax positions totaled $5,916,46 1. FIN 48 requires that this amount be recorded on Entergy' s balance sheet as a tax liability. Entergy also reported that it made a cash deposit with the IRS in the amount of $1,294,683 associated with its FIN 48 liability.9 The ALJs concluded that Entergy's FIN 48 liability should be included in its ADFIT balance, but the amount of the cash deposit made by Entergy to the lRS attributable to Entergy ' s FIN 48 liability should not be included in Entergy's ADFIT balance. Accordingly, the ALJs recommended that $4,621,778 (Entergy's FIN 48 liability of $5,916,461 less the $1,294,683 cash deposit Entergy has already made with the IRS) be added to Entergy's AOFIT balance and thus 6 Remand of Docket No. 33309 {Application of AEP Texas Central Company for Authority to Change Rates), Docket No. 38772, Order on Remand (Jan. 20, 2011 ). 7 PFO at 26. 8 Id. at 24-26. 9 PFD at 26-27 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 6), 29 (c iting Rebuttal Testimony of Roberts, Entergy Ex. 64 at 8). PUC Docket No. 39896 Order on Rehearing Page 4 of 44 SOAH Docket N o . - 10 be used to offset Entergy's rate base. The ALJs did not recommend the addition of a deferred- tax-account rider because no party expressly advocated the addition of such a rider. 11 The Commission adopts the proposal for decision regarding the adjustment to Entergy's ADFIT for the amount attributable to Entergy's FIN 48 liability. However, the Commission also follows its precedent regarding the creation of a deferred-tax-account tracker and modifies the proposal for decision on this point. In CenterPoint's Electric Delivery Company's last rate case, Docket No. 38339, 12 the Commission found that tax schedule UTP-on which companies must describe, list, and rank each uncertain tax position-would provide the IRS auditors sufficient information to quickly determine which uncertain tax positions are of a magnitude worth investigating and that an IRS audit would be more likely to occur on some uncertain tax positions. If an IRS audit of a FIN 48 uncertain tax position results in an unfavorable outcome, the utility would not be able to earn a return on the amount paid to the IRS until the next rate case. Accordingly, the Commission authorizes Entergy to establish a rider to track unfavorable FIN-48 rulings by the IRS. The rider will also allow Entergy 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 unfavorable-tax-position audit. 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 Entergy subsequently prevails in an appeal of an unfavorable FIN-48 unfavorable-tax-position decision by the IRS, then any amounts collected under rider related to that overturned decision shall be credited back to ratepayers. The Commission adds new finding of fact 40A and deletes finding of fact 41 consistent with its decision to authorize the deferred-tax-account tracker. 10 PFD at 29. 11 /d.at 29. 12 Application of CenterPoint Electric Delivery Company, LLC for Authority to Change Rates, Docket No. 38339, Order on Rehearing at 3-4 (June 23, 2011). PUC Docket No. 39896 Order on Rehearing Page 5 or 44 SOAH Docket No•. . _ C. Capitalized Incentive Compensation Entergy capitalized into plant-in-service accounts some of the incentive payments made to employees and sought to include those amounts in rate base. The ALJs determined that Entergy should not be able to recover its financially based incentive-compensation costs. 13 Therefore, the portion of Entergy's incentive-compensation costs capitalized during the period July 1, 2009 through June 30, 20 I 0 that were financially based was excluded from Entergy's rate base. The ALJs also determined that the actual percentages should be used to determine the amount that is financially based. 14 In discussing Entergy's incentive compensation as a component of operating expenses, the ALJs adopted the method advocated by Texas Industrial Energy Consumers (TIEC) fo r calculating the amount of the financially based incentive costs. This method uses the actual percentage reductions applicable to each of the annual incentive programs that included a component of financially-based costs. 15 In its exceptions regarding capitalized incentive compensation, Entergy advocated for the use of T IEC's methodology to also calculate the amount of capitalized incentive compensation that is financiall y based. Entergy also noted that the amount of the disallowance reflected in the schedules, $1,333,352, was calculated using a disallowance factor that included incentive compensation tied to cost-control measures, which the ALJs found to be recoverable in the operating-cost incentive-compensation calculation. 16 When the TIEC methodology is applied to the capitalized incentive-compensation costs in rate base, the net result under TIEC ' s 17 methodology is that only $335,752.96 should be disallowed from capital costs. The Commission agrees that capitalized incentive compensation that is financially based should be excluded from rate base and that the exclusion only applies to incentive costs that Entergy capitalized during the period from July I, 2009 through June 30, 2010. However, the Commission finds that a consistent methodology should be used to calculate the amount to be 13 PFD at 171. 14 Id at 72. 15 Id. at 174; see also Entergy's Exceptions to the Proposal for Decision at 25-26 (July 23, 2012). 16 Entergy's Exceptions to the Proposal for Decision at 25-26. 17 Id. at 25-26. PUC Docket No. 39896 Order on Rehearing Page 6 of 44 SOAH Docket No. excluded and therefore that TIEC 's methodology should also be used for calculating the amount of capitalized financially based incentive-compensation costs that should be excluded from rate base. Accordingly, the total amount of capitalized incentive-compensation costs that should be disallowed from rate base is $335,752.96. Finding of fact 61 is modified to reflect this detennination. As noted by Commission Staff, this disallowance to plant-in-service alters the expense for ad valorem taxes. Accounting for this disallowance, the appropriate expense amount for ad valorem taxes is $24,921 ,022, 18 an adjustment of $1 ,222,106 to Entergy's test year amount. Finding of fact 15 l is modified to reflect this adjustment to property taxes. D. Rate of Return and Cost of Capital The A Us found the proper range of an acceptable return on equity for Entergy would be from 9.3 percent to 10.0 percent. 19 The mid-point of the range is 9.65 percent. The ALJs found that the effe·ct of unsettled economic conditions facing utilities on the appropriate return on equity should be taken into account and that the effect would be to move the ultimate return on equity towards the upper limits of the range that was determined to be reasonable.20 The ALJs found that the reasonable adjustment would be 15 basis points, moving the reasonable return on equity to 9.80 percent. 21 The Commission must establish a reasonable return for a utility and must consider applicable factors. 22 The Commission disagrees with the ALJs that a utility's return on equity should be detennined using an adder to reflect unsettled economic conditions facing utilities. The Commission agrees with the ALJs, however, that a return on equity of 9.80 percent will allow Entergy a reasonable opportunity to earn a reasonable return on its invested capital, but finds this rate appropriate independent of the 15-point adder recommended by the ALJs. A return on equity of 9.80 percent is within the range of an acceptable return on equity found by 18 Commission Number-Run Memorandum at 2 (Aug. 28, 2012). 19 PFD at 94. 20 Id 21 Id at 94. 22 PURA §§ 36.051 , .052. PUC O~ket No. 39896 Order on Rehearing Page 7 of 44 SOAH Docket N o . - the ALJs. Accordingly, the Commission adds new finding of fact 65A to reflect the Commission' s decision on this point. E. Purchased-Power Capacity Expense The ALJs rejected Entergy's request to recover $31 million more in purchased-power capacity costs than its actual test-year expenses because Entergy had fai led to prove that the adjustment was known and measurable,23 and because the request violated the matching principle.24 Consequently, the ALJs recommended that Entergy' s test-year expenses of $245,432,884 be used to set rates in this docket. 25 Entergy pointed to an additional $533,002 of purchased-power capacity expenses that were properly included in Entergy's rate-filing package, but not provided for in the proposal for deci sion.26 The Commission finds that an additional $533,002 ($6,132 for test-year expenses for Southwest Power Pool fees, $654,082 for Toledo Bend hydro fixed-charges, and -$127,212 for an Entergy intra-system billing adjustment that were all recorded in FERC account 555) of purchased-power capacity costs were incurred during the test-year and should be added to the purchased-power capacity costs in Entergy' s revenue requirement. The Commission modifies findings of fact 72 and 86 to reflect the inclusion of the additional $533,002 of test-year purchased-power capacity costs, increasing the total amount to $245,965,886. F. Labor Costs - Incentive Compensation The ALJs found that $6, 196,03 7, representing Entergy's financially-based incentives paid 27 in the test-year, should be removed from Entergy' s O&M expenses. The ALJs agreed with Commission Staff and Cities that an additional reduction should be made to account for the FICA taxes that Entergy would have paid for those costs, 28 but did not include this reduction in a finding of fact. 23 PFD at 108-09. 24 Id. at 109. 15 Id 26 Entergy's Exceptions to the Proposal for Decision at 51 . 27 PFD at 175. 28 Id at 175-76. PUC Docket No. 39896 Order on Rehearing Page 8of 44 SOAH Docket N o . - The Commission agrees with the ALJs, but modifies finding of fact 133 to specifically include the decision that an additional reduction should be made to account for the FICA taxes Entergy would have paid on the disallowed financially-based incentive compensation. The Commission notes that this reduction for FICA taxes is reflected in the schedules attached to this Order.29 G. AffiJiate Transactions OPUC argued that Entergy's sales and marketing expenses exclusively benefit the larger commercial and industrial customers, but the majority of the sales, marketing, and customer service expenses are allocated to the operating companies based on customer counts. Therefore, the majority of these expenses are allocated to residential and small business customers. OPUC argued that it is inappropriate for residential and small business customers to pay for these expenses.30 The ALJs did not adopt OPUC's position on this issue. The Commission agrees with OPUC and reverses the proposal for decision regarding allocation of Entergy's sales and marketing expense and finds that $2.086 million of sales and marketing expense should be reallocated using direct assignment. The Commission has previously expressed its preference for direct assignment of affiliate expenses. 31 The Commission finds that the following amounts should be allocated based on a total-number-of- customers basis: ( l ) $46,490 for Project El OPCR56224 - Sales and Marketing - EGSI Texas; (2) $17,013 for Project F3PCD10049 - Regulated Retail Systems O&M; and (3) $30,167 fo r Project F3PPMMALl2 - Middle Market Mkt. Development. The remainder, $1,992,475, should be assigned to (l) General Service, (2) Large General Service and (3) Large Industrial Power Service.32 The reallocation has the effect of increasing the revenue requirement allocated to the large business class customers and reduces the revenue requirement for small business and residential customers. New finding of fact l64A is added to reflect the proper allocation of these affiliate transactions. 29 See Commission Number Run-Memorandum at 3 (Aug. 28, 2012). 30 Direct Testimony of Carol Szerszen, OPUC Ex. I at 44-45. JI Application of Central Power and light Company for Authority to Change Rates, Docket No. 14965, Second Order on Rehearing at 87, COL 29 (Oct. 16, 1997). 32 Direct Testimony of Carol Szerszen, OPUC Ex. I at Schedule CAS-7. PUC Docket No. 39896 Order on Rehearing Page 9 or 44 SOAH Docket No. H. Fuel Reconciliation Entergy proposed to allocate costs for the fuel reconciliation to customers using a line- loss study performed in 1997. Entergy conducted a line-loss study for the year ending December 3 1, 2010, which falls in the middle of the two year fuel reconciliation period- July 2009 through June 20 I I- and therefore reflects the actual line losses experienced by the customer classes during the reconciliation period. Cities argued that the allocation of fuel costs incurred over the reconciliation period should reflect the current line-loss study performed by Entergy for this case and recommended approval on a going-forward basis. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding described in P.U.C. SussT. R. 25.236. P.U.C. SussT. 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.33 Cities calculated a $3,981 ,27 1 reduction to the Texas retail fuel expenses incurred over the reconciliation period using the current line-losses. The ALJs rejected Cities' proposed adjustment finding that the P.U.C. SUBST. R. 25.237(c)(2)(B) requires the use of Commission- approved line losses that were in effect at the time fuel costs were billed to customers in a fuel reconciliation.34 The Commission agrees with Cities and reverses the proposal for decision regarding which line-loss factors should be used in Entergy's fuel reconciliation. Entergy used the 2010 study line-loss calculations to calculate the demand- and energy-related allocations in its cost of service analysis supporting its requested base rates. These same currently available line-loss factors should have been uti lized in Entergy's fuel reconciliation. The Commission finds that Entergy' s 20 l 0 line-loss factors should be used to calculate Entergy ' s fuel reconciliation over-recovery. As a result, Entergy's fuel reconciliation over-recovery should be reduced by $3,981 ,271. Finding of fact 246A and conclusions of law l 9A and 198 are added to reflect the Commission's finding that the 2010 line-loss factors be used to reconcile Entergy's fuel costs. 33 Cities' Exceptions to the Proposal for Decision at 20-21 (July 23, 2012) . 4 .1 PFD at 327-328. PUC Docket No. 39896 Order on Rehearing Page lO of 44 SOAH Docket No. I. MISO Transition Expenses During the Commission' s consideration of the proposal for decision, the parties that contested the amount of Entergy's MISO transition expenses and how the transition expenses should be accounted for reached announced on the record that they had reached an agreement on these issues.35 Those parties agreed that the MISO transition expenses would not be deferred and that Entergy' s base rates should include $1.6 million for MISO transition expense. 36 The Commission adopts the agreement of the parties and accordingly modifies finding of fact 251 and deletes finding of fact 252. J. Purchased-Power Capacity Cost Baseline The Commission modified the amount of purchased-power capacity expense in the test-year to be $245,965,886 (see section E above). Finding of fact 255 is modified to reflect the change to the proper test-year purchased-power capacity expense. K. Other Issues New findings of fact 17A, 17B, 17C, 170, and 17 E are added to reflect procedural aspects of the case after issuance of the proposal for decision. In addition, to reflect corrections recommended by the ALJs, findings of fact 116, 123, 192, 194, and 202 are modified; and new finding of fact l 82A is added. The Commission adopts the following findings of fact and conclusions of law: II. Findings of Fact Procedural History 1. Entergy Texas, Inc. (ETI or the company) is an investor-owned electric utility with a retail service area located in southeastern Texas. " Open Meeting Tr. at 138 (Aug. 17, 201 2). 36 Id. PUC Docket No. 39896 Order on Rehearing Page 11 of 44 SOAH Docket No. 2. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011 , ETI served approximately 412,000 Texas retail customers. The Federal Energy Regulatory Commission (FERC) regulates ETl ' s wholesale electric operations. 3. On November 28, 2011, ETI fi led an application requesting approval of: (I) a proposed increase in annual base rate revenues of approximately $ 111 .8 million over adjusted test- year revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying ETI's application and including new riders for recovery of costs related to purchased-power capacity and renewable energy credit requirements; (3) a request for final reconciliation of ETI's fuel and purchased-power costs for the reconciliation period from July 1, 2009 to June 30, 201 l; and (4) certain waivers to the instructions in RFP Schedule V accompanying ETI's application. 4. The 12-month test-year employed in ETI' s filing ended on June 30, 20 11 (test-year). 5. ETI provided notice by publication for four consecutive weeks before the effective date of the proposed rate change in newspapers having general circulation in each county of ETI's Texas service territory. ETI also mailed notice of its proposed rate change to all of its customers. Additionally, ETI timely served notice of its statement of intent to change rates on all municipalities retaining original jurisdiction over its rates and services. 6. The following parties were granted intervenor status in this docket: Office of Public Utility Counsel; the 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 (Cities), the Kroger Co. (Kroger); State Agencies; Texas Industrial Energy Consumers; East Texas Electric Cooperative, Inc.; the United States Department of Energy (DOE); and Wal-Mart Stores Texas, LLC, and Sam's East, Inc. (Wal-Mart). The Staff (Staff) of the Public Utility Commission of Texas (Commission or PUC) was also a participant in this docket. 7. On November 29, 201 1, the Commission referred this case to the State Office of Administrative Hearings (SOAH). PUC Docket No. 39896 Order on Rehearing Page 12 of 44 SOAH Docket No. 8. On December 7, 2011, the Commission issued its order requesting briefing on threshold legal/policy issues. 9. On December 19, 2011, the Commission issued its Preliminary Order, identifying 31 issues to be addressed in this proceeding. 10. On December 20, 2011, the Administrative Law Judges (ALJs) issued SOAH Order No. 2, which approved an agreement among the parties to establish a June 30, 2012 effective date for the company 's new rates resulting from this case pursuant to certain agreed language and consolidate Application of Entergy Texas, Inc. for Authority 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 13, 2012, the ALJs 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 participate as counsel for Wal-Mart. 12. On January 19, 2012, 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 Commission petitions for review of the rate ordinances of the municipalities exercising original jurisdiction within its service territory. All such appeals were consolidated for determination in this proceeding. 14. On April 4, 2012, the ALJs issued SOAH Order No. 13 severing rate case expense issues into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from 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. PUC Docket No. 39896 Order on Rehearing Page 13 of 44 SOAH Docket No. - 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 ALJs tiled a letter with the Commission recommending changes to the PFD. l 7B At the July 27, 20 12 open meeting, ETI agreed to extend time to August 31, 20 12 to provide the Commission sufficient time to consider the issues in this proceeding. l 7C. The Commission considered the proposal for decision at the August 17, 2012 and August 30, 2012 open meetings. 170. At the August 30, 20 12 open meeting, ETI agreed to extend time to September 14, 20 12 to provide the Commission sufficient time to consider the issues in this proceeding. l 7E. At the August 17, 2012 open meeting, parties announced on the record a settlement of the amount of costs for the transition to MISO. 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 resolved 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 shou ld 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 amortization rate beginning August 15, 2010. PUC Docket No. 39896 Order on Rehearing Page 14 of 44 SOAH Docket N o . - 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 (SF AS) 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 CWIP in rate base, and there was insufficient evidence showing that major projects under construction were efficiently and prudently managed. 27. The portion of the prepaid pension assets balance that is capitalized to CWIP should not be included in ETI 's rate base. 28. The remainder of the prepaid pension assets balance should be included in ETI'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 $8,858,93 3. 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 construction on the portion of ETI ' s Prepaid Pension Assets Balance capitalized to CWIP. 30. The Financial Accounting Standard Board (F ASB) 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 tax 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. 31. FIN 48 requires ETI to remove the amount of its uncertain tax positions from its Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting PUC Docket No. 39896 Order on Rehearing Page IS of 44 SOAH Docket No•• • 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 liabi lities, meaning ETI has, thus far, avoided paying to the IRS $5,916,46 1 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 the IRS. 33. ETI has deposited $ 1,294,683 with the IRS in connection with the FIN 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 liabi lity. 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 ETl's full FIN 48 liability of $5,916,461 less the $ 1,294,683 cash deposit ETI has made with the IRS for the FIN 48 liability) should be added to ETI's ADFIT and thus be used to reduce ETI's rate base. 40. ETI 's application and proposed tariffs do not include a request for a tracking mechanism or rider to collect a return on the FfN 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 FfN 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 tederal 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. PUC Docket No. 39896 Order on Rehearing Page 16 of 44 SOAH Docket No•. . _ 41 . Deleted. 42. Investor-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 amount of working capital, not specifically addressed 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 ETl 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). 45. It is reasonable to establish ETI's cash working capital requirement based on ETI's lead- lag study as updated in Jay 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 facie case concerning the prudence of its storm 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 storm reserve balance was negative $59,799,744. 51. The amount of $9,846,037, representing the value of the average coal inventory maintained at ETI ' s coal-burning facilities, is reasonable, necessary, and should be included in rate base. PUC Docket No. 39896 Order on Rehearing Page 17 of 44 SOAH Docket N o - 52. The Spindletop gas storage facility (Spindlctop 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 far western region of the Entergy system. 54. It is reasonable and appropriate to include ETI' s share of the costs to operate the Spindletop facil ity in rate base. 55. Staff recommended updating ETI' s balance amounts for short-term assets to the 13- month period ending December 20 11 , which was the most recent information available. Staff's 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, 134,35 1; materials and supplies at $29,285,42 1; 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 $1,127,778 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 payments made by ETI for incentive compensation tied to financial goals. 6 1. The portion of ETI's incentive payments that are capitalized and that are financially- based should be excluded from ETI's rate base because the benefits of such payments inure most immediately and predominantly to ETI' s shareholders, rather than its electric PUC Docket No. 39896 Order on Rehearing Page 18 of 44 SOAH Docket No. customers. ETl' 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-based should be excluded from rate base, but only for incentive costs that ETI capitalized during the period from July l , 2009 (the end of the prior test-year) through June 30, 2010 (the commencement of the current test-year). Rate ofReturn and Cost of Caoital 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. PUC Docket No. 39896 Order on Reheuing Page 19 or 44 SOAH Docket N o . - 71. ETl 's overall rate ofreturn should be set as follows: CAPITAL WEIGHTED A VG COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL LONG-TERM DEBT 50.08% 6.74% 3.38% COMMON EQUITY 49.92% 9.80% 4.89% TOTAL 100.00% 8.27% Ope,ating 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 ETl's projections of its purchased capacity expenses during a period beginning June I, 2012 and ending May 31 , 20 13 (the rate-year). 74. ETl'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 ETI 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 under the contract, even though that assumption is inconsistent with ETI's historical experience. 78. There is substantial uncertainty with regard to ETI's projection of its rate-year third-party capacity-contract payments. 79. ETI's estimates of its rate-year purchases under affili ate contracts are based on a mathematical formula set out in Schedule MSS-4. PUC Docket No. 39896 Order on Rehearing Page 20 of 44 SOAH Docket No. 80. The MSS-4 fonnula for rate-year af1iliate 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 EAi WBL Contract) that was not signed until April 11 , 2012. 82. There is uncertainty about whether the EAi WBL Contract will ever go into effect 83. ETI projects purchasing over 300 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. 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. ETI's projection of its rate-year transmission equalization expenses is uncertain and speculati ve because it depends on a number of variables, including future transmission investments, deterred 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 PUC Docket No. 39896 Order on Rthtuing Page 21or44 SOAH Docket N o . - 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 it-; 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. Ell'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. ETl's transmission equalization expense in this case should be based on the test-year level of$1,753,797. 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 amortization 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. I 00. The retirement (actuarial) rate method, rather than the interim retirement method, should be used in the development of production plant depreciation rates. l0 I . Production plant net salvage is reasonably based on the negative five percent net salvage in existing rates. PUC Docket No. 39896 Order on Rehearing Page 22 of44 SOAH Docket No. I02. The net salvage rate of negative IO 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 ETI'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. I06. 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. I 07. A service life of 65 years and a dispersion curve of R3 for ETI's distribution structures and improvements (FERC Account 361) are the most reasonable of those proposed and should be approved. I 08. A service life of 40 years and a dispersion curve of RI for ETI's distribution poles, towers, and fixtures (FERC Account 364) are the most reasonable of those proposed and should be approved. I09. A service life of 39 years and a dispersion curve of R0.5 for ETI's distribution overhead conductors and devices (FERC Account 365) are the most reasonable of those proposed and should be approved. I I 0. A service life of 35 years and a dispersion curve of R l.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. PUC Docket No. 39896 Order on Rehearing Page 23 of 44 SOAH Docket N o . - 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. 11 3. The net salvage rate of negative five percent for ETI's distribution structures and improvements (FERC Account 36 1) is the most reasonable of those proposed and should be adopted. 114. The net salvage rate of negative 10 percent for ETl's distribution station equipment (FERC Account 362) is the most reasonable of those proposed and should be adopted. 11 5. The net salvage rate of negative seven percent for ETl's distribution overhead conductors and devices (FERC Account 365) is the most reasonable of those proposed and should be adopted. 116. The net salvage rate of positive five percent for ETl'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 10 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 10 percent for ETI' 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 ETI'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 reasonable of those proposed and should be adopted. 121. It is reasonable to convert 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. PUC Docket No. 39896 Order on Rehearing Page 24 of 44 SOAH Docket No. 123. FERC pronouncement AR-15 requires amortization over the same life as recommended based on standard life analysis. A standard life 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. In 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 counting of three ETI and one ES I employee; (b) 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) payroll 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, annual 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 predominant benefit to ratepayers. PUC Docket No. 39896 Order on Rehearing Page 25 of 44 SOAH Docket No. 130. Incentives to achieve operational measures are necessary and reasonable to provide utility services but those to achieve financial measures are not. 131. The $5,3 76,975 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 financia l 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 FICA taxes ETI would have paid on the disallowed financially based incentive compensation. 134. The amount of incentive compensation that should be included in the cost of service is $7,991, 707. 135. To attract and retain highly qualified employees, the Entergy companies provide a total package of compensation and benefits that is equivalent in scope and cost with what other comparable companies within the utility business and other industries provide for their employees. 136. When using a benchmark analysis to compare companies' levels of compensation, it is reasonable to view the market level of compensation as a range rather than a precise, single point. 137. ETI' s base pay levels are at market. 138. ETI's benefits plan levels are within a reasonable range of market levels. 139. ETI's level of compensation and benefits expense is reasonable and necessary. 140. ETI provides non-qualified supplemental executive retirement plans for highly compensated individuals such as key managerial employees and executives that, because of limitations imposed under the Internal Revenue Code, would otherwise not receive retirement benefits on their annual compensation over $245,000 per year. PUC Docket No. 39896 Order on Rehearing Page 26 of 44 SOAH Docket No•. . . _ 141. ETI' s non-qualified supplemental executive retirement plans are discretionary costs designed to attract, retain, and reward highly compensated employees whose interests are more closely aligned with those of the shareholders than the customers. 142. ETI's non-qualified executive retirement benefits in the amount of $2, 114,931 are not reasonable or necessary to provide utility service to the public, not in the public interest, and should not be included in ETI's cost of service. 143. For the employee market in which ETI operates, most peer companies offer moving assistance. Such assistance is expected by employees, and ETI would be placed at a competitive disadvantage if it did not offer relocation expenses. 144. ETI's relocation expenses were reasonable and necessary. 145. The company's requested operating expenses should be reduced by $40,620 to reflect the removal of certain executive prerequisites proposed by Staff. 146. Staff properly adjusted the company's requested interest expense of$68,985 by removing $25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year 2012), leaving a recommended interest expense of $43,047. 147. During the test-year, ETI's property tax expense equaled $23,708,829. 148. ETI requested an upward proforma adjustment of $2,592,420, to account for the property tax expenses ETI estimates it will pay in the rate-year. 149. ETI's requested proforma adjustment is not reasonable because it is based, in part, upon the prediction that ETI's property tax rate will be increased in 2012, a change that is speculative is not known and measurable. 150. Staff's recommendation to increase ETI's test-year property tax expenses by $1,214,688 is based on the historical effective tax rate applied to the known test-year-end plant in service value, consistent with Commission precedent, and based upon known and measurable changes. 151. ETI's test-year property tax burden should be adjusted upward by $1,222,106 for a total expense of $24,921,022. PUC Docket No. 39896 Order on Rehearing Page 27 or44 SOAH Docket N o . - 152. Staff recommended reducing ETI's advertising, dues, and contributions expenses by $12,800. The recommendation, which no party contested, should be adopted. 153. The final cost of service should reflect changes to cost of service that affect other components of the revenue requirement such as the calculation of the Texas state gross receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible Expenses. 154. The company's requested Federal income tax expense is reasonable and necessary. 155. ETI's request for $2,019,000 to be included in its cost of service to account for the company' s annual decommissioning expenses associated with River Bend is not reasonable because it is not based upon "the most current information reasonably available regarding the cost of decommissioning" as required by P.U.C. SuesT. R. 25.231(b)(l)(F)(i). 156. Based on the most current information reasonably available, the appropriate level of decommissioning costs to be included in ETI's cost of service is $1, 126,000. 157. ETI' s appropriate total annual self-insurance storm damage reserve expense is $8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its current deficit. 158. ETI' s appropriate target self-insurance storm damage reserve is $17,595,000. 159. ETI should continue recording its annual storm damage reserve accrual until modified by a Commission order. 160. The operating costs of the Spindletop facility are reasonable and necessary. 161. The operating costs of the Spindletop facility paid to PB Energy Storage Services are eligible fuel expenses. Affiliate Transactions 162. ETI affiliates charged ETI $78,998,777 for services during the test-year. The majority of these O&M expenses- $69,098,041- were charged to ETI by ESL The remaining affiliate services were charged (or credited) to ETI by: Entergy Gulf States Louisiana, PUC Docket No. 39896 Order on Rehearing Page 28 of 44 SOAH Docket No. L.L.C.; Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.; Entergy Operations, Inc.; and non-regulated affiliates. 163. ESI follows a number of processes to ensure that affiliate charges are reasonable and necessary and that ETI and its affiliates are charged the same rate for similar services. These processes include: (a) the use of service agreements to define the level of service required and the cost of those services; (b) direct billing of affiliate expenses where possible; (c) reasonable allocation methodologies for costs that cannot be directly billed; (d) budgeting processes and controls to provide budgeted costs that are reasonable and necessary to ensure appropriate levels of service to its customers; and (e) oversight controls by ETI's Affiliate Accounting and Allocations Department. 164. Affiliates charged expenses to ETI through 1292 project codes during the test-year. l 64A. The $2,086, 145 in affiliate transactions related to sales and marketing expenses should be reallocated using direct assignment. The following amounts should be allocated to all retail classes in proportion to number of customers: ( I) $46,490 for Project EIOPCR56224 - Sales and Marketing - EGSI Texas; (2) $ 17,013 for Project F3PCD10049 - Regulated Retail Systems O&M; and (3) $30,167 for Project F3PPMMALI2 - Middle Market Mkt. Development. The remainder, $1 ,992,475, should be assigned to ( 1) General Service, (2) Large General Service and (3) Large Industrial Power Service. 165. ETI agreed to remove the following affiliate transactions from its application: ( I) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553; (2) Project F3 PCS PETE I (Entergy-Tulane Energy Institute) in the amount of $14,288; and (3) Project F5PPKATRPT (Stonn Cost Processing & Review) in the amount of $929. 166. The $356,151 (which figure includes the $112,53 1 agreed to by ETI) of costs associated with Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non Qual Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the provision of electric utility service and are not in the public interest. 167. The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts Settlement) are not nonnally-recurring costs and should not be recoverable. PUC Docket No. 39896 Order on Rehearing Page 29 of44 SOAH Docket N o . - 168. The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are related to ESl's operations, it is more immediately related to Entergy Louisiana, Inc. and Entergy New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.' 169. The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy Management for ESI) are research and development costs related to energy efficiency programs. As such, they should be recovered through the energy efficiency cost recovery factor rather than base rates. 170. Except as noted in the above findings of fact Nos. 162-169, all remaining affiliate transactions were reasonable and necessary, were allowable, were charged to ETI at a price no higher than was charged by the supplying affiliate to other affiliates, and the rate charged is a reasonable approximation of the cost of providing service. Jurisdictional Cost Allocation 171. ETI has one full or partial requirements wholesale customer - East Texas Electric Cooperative, Inc. 172. ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set the wholesale load results in a retail production demand allocation factor of 95.3838 percent. 173. The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used by the FERC to allocate between jurisdictions. 174. Using l 2CP methodology to allocate production costs between the wholesale and retail jurisdictions is the best method to reflect cost responsibility and is appropriate based on ETI's reliance on capacity purchases. Class Cost Allocg/ion and Rate Design 175. There is no express statutory authorization for ETI's proposed Renewable Energy Credits rider (REC rider). 176. REC rider constitutes improper piecemeal ratemaking and should be rejected. PUC Docket No. 39896 Order on Rehearing Page JO of 44 SOAH Docket No. 177. ETI's test-year expense for renewable energy credits, $623,303, is reasonable and necessary and should be included in base rates. 178. Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use public rights-of-way to locate its facilities within municipal limits. 179. ETI is an integrated utility system. ETI's facilities located within municipal limits benefit all customers, whether the customers are located inside or outside of the municipal limits. 180. Because all customers benefit from ETI' s rental of municipal right-of-way, municipal franchise fees should be charged to all customers in ETI's service area, regardless of geographic location. 181. It is reasonable and consistent with the Public Utility Regulatory Act (PURA) § 33.008(b) that MFF be allocated to each customer class on the basis of in-city kilowatt hour (kWh) sales, without an adjustment for the MFF rate in the municipality in which a given kWh sale occurred. 182. The same reasons for allocating and collecting MFF as set out in Finding of Fact Nos. 178-181 also apply to the allocation and collection of Miscellaneous Gross Receipts Taxes. The company's proposed allocation of these costs to all retail customer classes based on customer class revenues relative to total revenues is appropriate. 182A. ETI's proposed gross plant-based allocator is an appropriate method for allocating the Texas franchise tax. 183. The Average and Excess ( A&E) 4CP method for allocating capacity-related production costs, including reserve equalization payments, to the retail classes is a standard methodology and the most reasonable methodology. 184. The A&E 4CP method for allocating transmission costs to the retail classes is standard and the most reasonable methodology. 185. ETI appropriately followed the rate class revenue requirements from its cost of service study to allocate costs among customer classes. ETl's revenue allocation properly sets rates at each class's cost of service. PUC Docket No. 39896 Order on Rehearing PageJI of44 SOAH Docket No. - 186. It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any replacement of a functioning light with a lower-wattage bulb. 187. It is appropriate to require ETI to prepare and fil e, as part of its next base rate case, a study regarding the foasi bil ity of instituting LED-based rates and, if the study shows that such rates are feasible, ETI should file proposals for LED-based lighting and traffic signal rates in its next rate case. 188. An agreement was reached by the parties and approved by the Commission in Docket No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand ratchet for existing customers in the Large Industrial Power Service (LI PS), Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day, Large General Service, and Large General Service-Time of Day rate schedules. 189. ETI's proposed tariffs in this case did not remove the life-of -contract demand ratchet from these rate schedules consistent with the parties' agreement in Docket No. 37744. 190. A perpetual billing obl igation based on a life-of-contract demand ratchet, as ETI proposed, is not reasonable. 19 1. ETI's proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the agreement that was adopted by the Commission as just and reasonable in Docket No. 37744. Accordingly, these tariffs should be modified as set out in Findings of Fact No. 192-1 94. l 92. ETI's Schedule LIPS and LIPS Time of Day§ Vl should be changed to read: DETERMINATION OF BILLING LOAD The kW of Billing Load will be the greatest of the fo llowing: {A) The Customer's maximum measured 30-minute demand during any 30-minute interval of the current billing month, subject to §§ Ill , IV and V above; or (B) 75% of Contract Power as defined in § Vil; or (C) 2,500 kW. PUC Docket No. 39896 Order on Rehearing Page 32 of44 SOAH Docket No. 193. ETl's Schedule LIPS and LIPS Time of Day§ VU should be changed to read: DETERMINATION OF CONTRACT POWER Unless Company gives customer written notice to the contrary, Contract Power will be defined as below: Contract Power - the highest load established under § VI(A) above during the 12 months ending with the current month. For the initial 12 months of Customer's service under the currently effective contract, the Contract Power shall be the kW specified in the currently effective contract unless exceeded in any month during the initial 12-month period. 194. The Large General Service, Large General Service-Time of Day, General Service, and General Service-Time of Day schedules should be similarly revised to eliminate ETI's life-of-contract demand ratchet. 195. In its proposed rate design for the LIPS class, the company took a conservative approach and increased the current rates by an equal percentage. This minimized customer bill impacts while maintaining cost causation principles on a rate class basis. 196. It is a reasonable move towards cost of service to add a customer charge of $630 to the LIPS rate schedule with subsequent increases to be considered in subsequent base rate cases. 197. It is a reasonable move towards cost of service to slightly decrease the LIPS energy charges and increase the demand charges as proposed by Staff witness William B. Abbott. 198. DOE proposed a new Schedule LIPS rider-Schedule "Schedulable Intermittent Pumping Service" (SIPS) for load schedulable at least four weeks in advance, that occurs in the off-season (October through May), that can be cancelled at any time, and for load not lasting more than 80 hours in a year. For customers whose loads match these SIPS characteristics (for example, DOE's Strategic Petroleum Reserve), the 12-month demand ratchet provision of Schedule LIPS does not apply to demands set under the provisions of the SCPS rider. The monthly demand set under the SIPS provisions would be applicable for billing purposes only in the month in which it occurred. In short, if a customer set a PUC Docket No. 39896 Ortler on Rehearing Page 33 of 44 SOAH Docket No. - 12-month ratchet demand in that month, it would be forgiven and not applicable in the succeeding 12 months. 199. DOE's proposed Schedule SIPS ts not restricted solely to the DOE and should be adopted. It more closely addresses specific customer characteristics and provides for cost-based rates, as does another ETI rider applicable to Pipeline Pumping Service. 200. Standby Maintenance Service (SMS) is available to customers who have their own generation equipment and who contract for this service from ETI. 201. P.U.C. SUBST. R. 25.242(k)(l) provides that rates for sales of standby and maintenance power to qualifying faci lities should recognize system wide costing principles and should not be discriminatory. 202. It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer charge equivalent to that of the LIPS rate schedule only for SMS customers not purchasing supplementary power under another applicable rate; and (b) revising the tariff as follows: Distribution Transmission Charge (less than 69KV) (69KV and greater) Billing Load Charge ($/kW): Standby $2.46 $0.79 Maintenance $2.27 $0.60 Non-Fuel Ener!!v Charge (¢/kWh) On-Peak 4.245¢ 4.074¢ Off-Peak 0.575¢ 0.552¢ 203. ETI's Additional Facilities Charge rider (Schedule AFC) prescribes the monthly rental charge paid by a customer when ETI installs faci lities for that customer that would not normally be supplied, such as line extensions, transformers, or dual feeds. 204. ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge. Option B, which applies when a customer elects to amortize the directly-assigned facil ities over a shorter term ranging from one to ten years, has a variable monthly charge. There is also a term charge that applies after the faci lity has been fully depreciated. PUC Docket No. 39896 Order on Rehearing Page 34 of 44 SOAH Docket No.- 205. It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.11 percent per month of the installed cost of all facilities included in the agreement for additional facilities. 206. It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and the Post Term Recovery Charge as follows: Selected Recovery Term Recovery Term Charge Post Recovery Term Charge 1 9.52% 0.28% 2 5. 14% 0.28% 3 3.68% 0.28% 4 2.95% 0.28% 5 2.52% 0.28% 6 2.23% 0.28% 7 2.03% 0.28% 8 1.88% 0.28% 9 1.76% 0.28% 10 1.67% 0.28% 207. The revisions in the above findings of fact to Schedule AFC rates reasonably reflect the costs of running, operating, and maintaining the directly-assigned facilities. 208. It is reasonable to modify the Large General Service rate schedule by increasing the demand charge from $8.56 to $11.43; decreasing the energy charge from $.00854 to $.00458; and reducing the customer charge to $260.00. 209. Staff's proposed change to the General Service (GS) rate schedule to gradually move GS customers towards their cost of service by recommending a decrease in the customer charge from the current rate of $41.09 to $39.91, and a decrease in the energy charges is reasonable and should be adopted. 2 10. ETI's Residential Service (RS) rate schedule is composed of two elements: a customer charge and a consumption-based energy charge. In the months November through April (winter), the rates are structured as a declining block, in which the price of each unit is reduced after a defined level of usage. ETI's proposed increase in the RS customer charge to $6 per month is reasonable and should be adopted. For the RS summer rate and PUC Docket No. 39896 Order on Rehearing Page 35 of 44 SOAH Docket No. - the first winter block rate, the 6.296¢ per kWh energy charge resulting from the increased revenue requirement fo r residential customers is reasonable and should be adopted. 2 11 . ETI's Schedule RS declining block rate structure is contrary to energy-efficiency efforts and ~he Legislature's goal of reducing both energy demand and energy consumption in Texas, as stated in PURA § 39.905. 2 12. Schedule RS winter block rates should be modified consistent with the goal set out in PURA § 39.905, with the initial phase-in of a 20 percent reduction in the block differential proposed by ETI and subsequent reductions should be reviewed for consideration at the occurrence of each rate case filing. 213. Other elements of Schedule RS are just and reasonable. Fuel Rec1mci/iation 2 14. ETI incurred $616,248 ,686 in natural-gas expenses during the reconciliation period, which is from July 2009 through June 2011. 215. ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and negotiated operational balancing agreements with various pipeline companies. 2 16. ETI employed a diversified portfolio of gas supply and transportation agreements to meet its natural-gas requirements, and ETI prudently managed its gas-supply contracts. 217. ETI' s natural gas expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers. 2 18. ETI incurred $90,82 1,317 in coal expenses during the reconciliation period. 219. ETI prudently managed its coal and coal-related contracts during the reconciliation period. 220. ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal burned at the Big Cajun II, Unit 3 facility. 22 l. ETI's coal expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers. PUC Docket No. 39896 Order on Rehearing Page36 of 44 SOAH C>ocket N o . - 222. ETI incurred $990,04 1,434 in purchased-energy expenses during the reconciliation period. 223. The Entergy System's planning and procurement processes for purchased-power produced a reasonable mix of purchased resources at a reasonable price. 224. During the reconciliation period, ETI took advantage of opportunities in the fuel and purchased-power markets to reduce costs and to mitigate against price volatility. 225. ETI' s purchased-energy expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers. 226. ETI provided sufficient contemporaneous documentation to support the reasonableness of its purchased-power planning and procurement processes and its actual power purchases during the reconciliation period. 227. The Entergy system sold power off system when the revenues were expected to be more than the incremental cost of supplying generation for the sale, subject to maintaining adequate reserves. 228. The System Agreement is the tariff approved by the FERC that provides the basis for the operation and planning of the Entergy system, including the six operating companies. The System Agreement governs the wholesale-power transactions among the operating companies by providing for joint operation and establishing the bases for equalization among the operating companies, including the costs associated with the construction, ownership, and operation of the Entergy system facilities. 229. Under the terms of the Entergy System Agreement, ETJ was allocated its share of revenues and expenses from off-system sales. 230. During the reconciliation period, ETI recorded off-system sales revenue in the amount of $376,671 ,969 in FERC Account 447 and credited 100 percent of off-system sales revenues and margins from off-system sales to eligible fuel expenses. 23 1. ETI properly recorded revenues from off-system sales and credited those revenues to eligible fuel costs. PUC Docket No. 39896 Order on Rehearing Page 37 of 44 SOAH Docket No.- 232. The Entergy system consists of six operating companies, including ETI, which are planned and operated as a single, integrated electric system under the tenns of the System Agreement. 233. Service schedule MSS-1 of the System Agreement detennines how the capabi lity and ownership costs of reserves for the Entergy system are equalized among the operating companies. These inter-system "reserve equalization" payments are the result of a fonnula rate related to the Entergy system's reserve capability that is applied on a monthly basis. 234. Reserve capability under service schedule MSS- 1 is capability in excess of the Entergy system's actual or planned load built or acquired to ensure the reliable, efficient operation of the electric system. 235. By approving service schedule MSS-1 , the FERC has approved the method by which the operating companies share the cost of maintaining sufficient reserves to provide reliability for the Entergy system as a whole. 236. Service schedule MSS-3 of the System Agreement detennines the pricing and exchange of energy among the operating companies. By approving service schedule MSS-3, the FERC has approved the method by which the operating companies are reimbursed for energy sold to the exchange energy pool and how that energy is purchased. 237. Service schedule MSS-4 of the System Agreement sets forth the method for determining the payment for unit power purchases between operating companies. By approving service schedule MSS-4, the FERC has approved the methodology for pricing inter-operating company unit power purchases. 238. The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day horizons. Once the planning process has identified the most economical resources that can be used to reliably meet the aggregate Entergy system demand, the next step is to procure the fuel necessary to operate the generating units as planned and acquire wholesale power from the market. PUC Docket No. 39896 Order on Rehearing Page 38 of 44 SOAH Docket No. 239. Once resources are procured to meet forecasted load, the Entergy system is operated during the current day using all the resources available to meet the total Entergy system demand. 240. After current-day operation, the System Agreement prescribes an accounting protocol to bill the costs of operating the system to the individual operating companies. This protocol is implemented via the intra-system bill to each operating company on a monthly basis. 241. ETI purchased power from affiliated operating companies per the terms of service schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3 to affiliated operating companies are reasonable and necessary, and the FERC has approved the pricing formula and the obligation to purchase the energy. ETI pays the same price per megawatt hour for energy under service schedule MSS-3 as does any other operating company purchasing energy under service schedule MSS-3 during the same hour. 242. The Spindletop facility is used primarily to ensure gas-supply reliability and guard against gas-supply curtailments that can occur as a result of extreme weather or other unusual events. 243. The Spindletop facility provides a secondary benefit of flexibility in gas supply. ETI can back down gas-fired generation to take advantage of more economical wholesale power, or use gas from storage to supplement gas-fired generation when load increases during the day and thereby avoid more expensive intra-day gas purchases. 244. ETI's customers received benefits from the Spindletop facility during the reconciliation period through reliable gas supplies and ETI's monthly and daily storage activity. 245. ETI prudently managed the Spindletop facility to provide reliability and flexibility of gas supply for the benefit of customers. 246. ETI proposed new loss factors, based on a December 2010 line-loss study, to be applied for the purpose of allocating its costs to its wholesale customers and retail customer classes. PUC Docket No. 39896 Order on Rehearing Page 39 of 44 SOAH Docket N o . - 246A. ETI 's 20 I 0 line-loss factors should be used to reconcile ETI's fuel costs. Therefore, ETI 's fuel reconciliation over-recovery should be reduced by $3, 981,271. 247. ETl's proposed loss factors are reasonable and shall be implemented on a prospective basis as a result of this final order. 248. ETI seeks a special-circumstances exception to recover $99,715 resulting from the FERC's reallocation of rough production equalization costs in FERC Order No. 720-A, and to treat such costs as eligible fuel expense. 249. Special circumstances exist and it is appropriate for ETI to_recover the rough production cost equalization costs reallocated to ETI as a result of the FERC 's decision in Order No. 720-A. Ot/1er Issues 250. A deferred accounting of ETI' s Midwest Independent Transmission System Operator (MISO) transition expenses is not necessary to carry out any requirement of PURA. 251. ETI should include $1.6 million in base rates for MISO transition expense. 252. Deleted. 253. Transmission Cost Recovery Factor basel ine values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation. 254. Distribution Cost Recovery Factor baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation. 255. The appropriate amount for ETI's purchased-power capacity expense to be included in base rates is $245,965,886. 256. The amount of ETI's purchased-power capacity expense includes third-party contracts, legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the amounts for all contracts should be included in the baseline for a purchased-capacity rider that may be approved in Project No. 39246 is an issue that should be decided in that project. PUC Docket No. 39896 Order on Rehearing Page 40 of 44 SOAH Docket No. III. Conclusions of Law 1. ETI is a "public utility" as that term is defined in PURA § 11.004(1) and an "electric utility" as that term is defined in PURA§ 31.002(6). 2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject matter of this application pursuant to PURA§§ 14.001, 32.001 , 32.101, 33.002, 33.051, 36.101- .111, and 36.203. 3. SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and TEX. Gov 'T CODE ANN. § 2003.049. 4. This docket was processed in accordance with the requirements of PURA and the Texas Administrative Procedure Act, Tex. Gov't Code Ann. Chapter 2001. 5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC. R. 22.5 l(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3). 6. Pursuant to PURA § 33.001 , each municipality in ETI's service area that has not ceded jurisdiction to the Commission has jurisdiction over the company's application, which seeks to change rates for distribution services within each municipality. 7. Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a municipality's rate proceeding. 8. ETJ has the burden of proving that the rate change it is requesting is just and reasonable pursuant to PURA § 36.006. 9. In compliance with PURA§ 36.05 1, ETI's overall revenues approved in this proceeding permit ETI a reasonable opportunity to earn a reasonable return on its invested capital used and useful in providing service to the public in excess of its reasonable and necessary operating expenses. I 0. Consistent with PURA § 36.053, the rates approved in this proceeding are based on original cost, Jess depreciation, of property used and useful to ETI in providing service. 11. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and P.U.C. SUBST. R. 25.23l(c)(2)(C)(i). PUC Docket No. 39896 Order on Rehearing Page 41 of44 SOAH Docket N o . - 12. Including the cash working capital approved in this proceeding in ETI's rate base is consistent with P.U.C. SUBST. R. 25.23 l (c)(2)(B)(iii)(IV), which allows a reasonable allowance for cash working capital to be included in rate base. 13. The ROE and overall rate of return authorized in this proceeding a re consistent with the requirements of PURA §§ 36.05 I and 36.052. 14. The affiliate expenses approved in this proceeding and included in ETl's rates meet the affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.- Austin 1984, no writ). 15. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and P.U.C. SUBST. R. 25.23 l (c)(2)(C)(i). 16. Pursuant to P.U.C. SUBST. R. 25.231 (b)(I)(F), the decommissioning expense approved in this case is based on the most current information reasonably available regarding the cost of decommissioning, the balance of funds in the decommissioning trust, anticipated escalation rates, the anticipated return on the funds in the decommissioning trust, and other relevant factors. 17. ETI has demonstrated that its eligible fuel expenses during the reconciliation period were reasonable and necessary expenses incurred to provide reliable electric service to retail customers as required by P.U.C. SUBST. R. 25.236(d)(l)(A). ETI has properly accounted for the amount of fuel-related revenues collected pursuant to the fuel factor during the reconciliation period as required by P.U.C. SUBST. R. 25.236(d)(l)(C). 18. ETI prudently managed the dispatch, operations, and maintenance of its fossil plants during the reconciliation period. 19. The reconciliation period level operating and maintenance expenses for the Spindletop facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a). l 9A. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding. PUC Docket No. 39896 Order on Rehe-.iring Page 42 of44 SOAH Docket No. 19B. P.U.C. Sussr. 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. 20. Special circumstances are warranted pursuant to P.U.C. Sus sr. R. 25.236(a)(6) to recover rough production equalization payments reallocated to ETI by the FERC. 21. ETI' s rates, as approved in this proceeding, are just and reasonable in accordance with PURA § 36.003. IV. Ordering Paragraphs In accordance with these findings of fact and conclusions of law, the Commission issues the following orders: I. The proposal for decision prepared by the SOAH ALJs is adopted to the extent consistent with this Order. 2. ETI's application is granted to the extent consistent with this Order. 3. ETI shall file in Tariff Control No. 40742 Compliance Tari.ff Pursuant to Final Order in Docket No. 39896 (Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment) tariffs consistent with this Order within 20 days of the date of this Order. No later than ten days after the date of the tariff filings, Staff shall file its comments recommending approval, modification, or rejection of the individual sheets of the tariff proposal. Responses to the Stafrs recommendation shall be filed no later than 15 days after the fil ing of the tariff. The Commission shall by letter approve, modify, or reject each tariff sheet, effective the date of the letter. 4. The tariff sheets shall be deemed approved and shall become effective on the expiration of 20 days from the date of filing, in the absence of written notification of modification or rejection by the Commission. If any sheets are modified or rejected, ETI shall file proposed revisions of those sheets in accordance with the Commission's letter within ten PUC Docket No. 39896 Order on Rehearing Page 43 of 44 SOAH Docket No. days of the date of that letter, and the review procedure set out above shall apply to the revised sheets. 5. Copies of all tariff-related filings shall be served on all parties ofrecord. 6. ETI shall prepare and file as part of its next base rate case a study regarding the feasibility of instituting LED-based rates and, if the study shows that such rates are feasible, ETI should file proposals for LED-based lighting and traffic signal rates in that case. If ETI has LED lighting customers taking service, the study shall include detailed information regarding differences in the cost of serving LED and non-LED lighting customers. ETI shall provide the results of this study to Cities and interested parties as soon as practicable, but no later than the filing of its next rate case. 7. AJI other motions, requests for entry of specific findings of fact and conclusions of law, and any other requests for general or specific reliet: if not expressly granted, are denied. PUC Docket No. 39896 Order on Rehearing Page 44 of 44 SOAH Docket N o . - SIGNED AT AUSTIN, TEXAS the PUBLIC UTILITY COMMISSION OF TEXAS ROLANDO PABLOS, COMMISSIONER I respectfully dissent regarding the utility- and executive-management-class affiliate transactions. To be consistent with Commission precedent in Docket No. 14965,37 the indirect costs of the management of Entergy's ultimate parent should not be borne by Texas ratepayers. Therefore, I would disallow the following: $ 173,867 for Project No. F3PCCPM001 (Corporate Performance Management); $3 72,919 for Project No. F3PCC31255 (Operations-Office of the CEO); and $74,485 for Project No. F3PPC00001 (Chief Operating Officer). I join the Commission in all other respects for this Order. KENNETHW. ANDER~J~ISSIONER q.\cadm\ordcrs\tinal\39000\39896<> on reh docx 37 Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965, Second Order on Rehearing (Oct. 16, 1997). SOAH DOCKET NO•• • • PUC DOCKET NO. 3Htt COMPANY NAMR En!MQY Teue, Inc TEST YEAR END ~un-11 Tmv. ., Toe.I (•) ~ -.. Compeny ... ToTeetv. .r (b) ~ Compan~ ....'" THIYHr Total Elec:trle (c) Commlellon Adj ...- . ToC ompa~ A!!l.,..t (d) CommlMlon AdlllNcl Total El9ctflc (•) • (c) • (d) MVEHUE REQUIREMENT Ope'811ane & M a i - s 1.291.684.714 (1.075.l48.117) s 218.538.597 s (2050.490) s 191.988.107 Revulatory ~end Credita 40700 s (8. 784,808) s 12,000.533 s 5,245,925 $ (324,121) $ 4 ,921.804 ACc19110n Expenee s 212,793 s (212.783) s s s lnle1911 on Cuelomer llepo9ita \ s s 68,985 s 68.985 s (25.938) s 43.047 o-wniaalonlng ExpenM s s $ s s Depfeelallon & AmorUzatlon Expenw s 78.072,459 s 22.558.698 s 98.631,157 s (8,253.318) s 92.Jn.841 Tu• Odle< Then Income T• •• s 63,023.906 $ (2.533. 159) $ 60.490,747 $ (2.874.508) $ 57.618,241 federal Income T - $ (23.407,031) s 67,298,739 s 43.889,708 s 6,181.364 $ 50.071.092 Cun9fl1 Slale Income Taxee s (127.519) s 89.787 s (37.732) s 37.732 s Deferred federel lnc:ome Taxee s 67,051,463 s (52.089.274) $ 14,982,189 $ (H,982.189) s DtfMecl S4ale 1ncCme Tuet $ 8 12.265 s (727.91 8) s 84,347 s (84.347) s lrwealrnant Tax Credlla 411.00 "'" ' s (1.8 11.177) s (48.429) s (1.857,808) s 1.857.808 s Coneolldated Tu S8\linga Adj..-! s s s s s Relum on 1"'"'80 Capital ! 155, 182,991 ! 155,182,991 I !14,562,3931 i 140,800,598 TOTAL s 1,4el,921,2SI s (t73,S49,t47) s 593,317,308 s (Sl,790,118) s 537,811,730 P1ut: Addbad<: P~ Power R- S&S.00 s 244,539,884 Addbeclc' lntenuptlllle Sentlcaa 55500 TotalAddbacu • 2",539.- Total COMM Rawnue it.qu....,,.nt s 782,151,814 •• • SONt DOCQ1' NO. PUC OOCKETNO. COWAHf- TUTYINllHO ---·· e....,T-lnc. c- ---- c-- - O&lll._ COMM-I °""-'T'IOMNl/0-....- ~·- Fuol Prod~-,.... ~ $00 501 I I r... v.., T- (91 5 ,338,227 (25$,2'2) • I ~ A4- ToT!!!Yur ('I 62.215 •• ~ - T••eY- T-'!- (C) 5.380."'2 (255,202) • I To~ ,.., (98,3e2) •• .-....- !!!!!!- (•)•(•l • '"' 5.280,080 (256.2'2) F.,.i.QI Fuol--Goo 501 501 • I 884,7'6 330,036,998 I I ($13,8411) (330,03Ulllll I •• 1154 • I I I "" Fuoi-Coll 501 I •9.170.<»4 I (48.818.7'8) 2,561.348 I (1,..efl) I 2.~.eeo s-e._ 502 I 3.llOO,llM I .0,940 I 3.941,743 I ($1,223) I 3,880,620 - e-"'- 505 I 2.~.•73 I 9,5 18 I 2.538.1118 I 8&t I 2.539,873 MlocS--E•- !508 I 8.133.1121 I 31,297 I a.187.218 I (70,307) I 8.092.811 607 I 131. 131 •• I 131.131 I •• 131, 131 -ol-__ NOX--bpenM sot I 1• 3.2. .) 03.2. . I I ••• • •• -ol-- NOX-AI-~ sot 11.ecw (11.00.0) I I --~-Eng 510 1,10$.598 3,100.201 • I 21.0)7 •.m • I I . '87,83) 3. 108,7M I I (18,:103) (e.872) I 1.188.330 3.101 .822 -olmllc-- 51 1 512 513 I •• 12,592.212 5.491 .510 • I 21.7•2 729.791 I I 12.8 13,980 8.221.301 I I (17.567) (27."°) I I 12.5118.397 8 ,183.78 1 _.._ HY189 -T-c_..&T- 589 I 008.802 I 8.215 s 456.087 I 155 I •55,212 T- - - l ! q u l p 570 • t.892.713 • I 7.288 I • 1,819.979 I I (14,177) ' 1,886,802 •' T- - O H U . . E " I ' 571 I 1,700.. .7 g'"' I I I s PIMl_ fot,....,,.Uoo I I I I ,.... ...._ WOll.3~ I I l , <00.3~ I (53.715.0<1 ) I 10UN,3M 55,873.6"5 I (26.311 .239) I 30.ee2.309 •• I \!0,914 81,914 I I &1.111 • Effltnlnmonl l l - I 3,412,378 (4,474,5091 (1,082, 190) I I (1,002.180) c·-~ R~-- l- I I (35.an.•1e1 I I 21.399.959 (35.8n.•71l 29,3911,119 I I (1 1,05',0M) •• (35,172,479) 15.312,786 _c...,__ Accu-DFIT I I (S24 ,339,et1 ) I I let,897,1.. 9.175.000 (454.371.547) 9, 175,000 I I a.m.005 (0.175.000) I• , ..7.973. 1'2) TOTA&. INYUTm CAPITAi. (RATI BAM) 1.nt.1•.• .., ..,o.... 1,7'0;1a1..., (. .. 21U37) 1,T00,128,1. . RATe Of llll!T~ ..,_ un ·~ MT\JllN Oii INYBTa> CJ#fTA&. 111,1'Ut1 111,1H ,lll 114.MJ.H>I 1'0.- .- ..... ION! DOCQT NO. PUC OOCUT NO. COWANY - TUT Yl!AA ENO - l_I, - Entorn T - . IM. ,_ T_. Y• r ......... c- c_..., R- " " Toon - ~ ~ To~ !--·- CO- ~ MjoMMI -lllA - -·- ror... v... T!!!I!!- Ro• - T-- Cb) Cdt tel • le,. Cell '"' 1<> p-- ltMoge!OPln o.v-- Mlle~ .... Tolll~PI. . IAllCI end I.and Rlgllta S!Nciu<• end 1...,,..,.. BO• PlontE~ 301 303 310 311 312 l,)Oe.IMl9 ii !:!1 717 98. 133,818 • .~1U73 172,130.020 388,477,042 •.058.233 "!!i!!!i 1, 157,922 1.099.011 '0.838,417 8, 305, 1:12 •22mg 107,291,&38 •.112.n3 174.029.845 391,315,4841 I I I I I • I 8.JOtl.1:12 122m.g 107,291,5)1 •.812.873 174,029.845 391,311,419 197,lle3,()30 __--Cooll Tu1tx)gelte1etot'I 314 188,175,111 8,787,911 197.183,0JO I _.,~ _ _ P!. . Equip 315 318 98,272.1'8 10.ace.oaJ 10.750,419 1.- .- 107,021,eot 12.712,547 I I •• 107,0XZ,eot 12.712,$41 317 419,211 (4 11,211) I I _ . , Eloc Equip 334 • 2111.~ 211.5)1 I I 219,5)8 , . ... Mlle. - Plan! Equip 335 s 37,289 882.'80.142 32.921.027 37,291 1195,111.llt I I - 37,2'8 .11 1.- 1...-_, ..... l""' e- - SINCUM end lmpmw M0.1 3ll02 352 s •• 9.571,171 33,122,811 21,tot,m 4.247,242 358,736 ee8.852 13.Sl7,121 33,979,123 22,579.129 I I s 13,127,121 33.'71,023 22,878,021 S-E~ Toir.n & Fbduf'W 383 • 354 • )4.t,eet,139 25.Je0.314 10,429.413 84.088 365,29U02 21.424,480 •• 358.211.002 25,424,480 -&F- ~eondldOIS &O 358 358 • • 188,563.323 188,098,911 13,724.n4 12.$70,2«> 180,288,047 171.089,231 •• 180,2&1.047 178.- .231 ~~ 367 s I ~Conduca R-ondT- 361 361 I • 321,717 202.7&5 321,717 202,716 • I :121,717 202.7N Toa.I Tr~ Pl..c 788,521,1193 42,082.342 110,591 ,235 8 10,581 ,23& ~"""" I.and " -'" s--- _ .,...._,. Patee, TCM9f'I Ii nxtur. OH~ &O.- ~Conduit 3801 380 2 m 381 38< *381 4, 178.1111 11.759,529 7.167.817 158,704,009 185,114,784 170,541,014 22,o&1.429 • s s s s 157,089 7, 585, 189 38.287,319 44.14 7,418 1.103,870 4,178.116 11.7511. 529 1.014,908 184,288.178 221.«>2, 1()3 214,818.'32 23, 171.291 • s s s I I ••• •• 4,171.1156 11 .751,529 8,014,908 184,2.el, 178 221,«>2,103 2 14.aaa,4:12 23,111,291 UOCon&Oow. 387 84.221,123 •• 7.121.IJ87 11,343,510 s • 91 ,)43.580 • ••• u...r.- 381 235.357,208 13.111.187 351.418,378 358,• 373 (229,908) 2.S78.038 2. 1&1 .130 s s 2. 151, 130 Total~Plllnt Non"- L""'"'9 37~2 12!~l 1,047,003.eot s !~!ml 1ll8,387.e85 [!;g2!1) 1,236,391.270 I s !!ZM~l 1,238,3111.270 c.._..,_ ~- 382 383 60,Sl3 H~130 90.823 ~-!:IQ 80,1123 H!IHl!I To 5.057, 177 5.057, 177 _,, ..,~ J90 s 53,909,113 3,034,857 51.-,470 58.- . 410 • - .530 •• (58~ - •s ~FumU9&E- 3811 938.3 10 938.310 38'2 s 17,8 48,803 1.223,mQ 1070.723 11.170,723 o.· ~~ T---Eq..

«l,4'8.318 143,o&e s s .00,4 11,311 143,0'8 Tot.I - P i n 137, 178,311 4.841,208 141,819.5211 141,819.$29 -CcnnAFVOC ,..,_ I (l.382.452) (t .312.452) (1,382,462> --- C""'* E l o c C - . - - s 2'8,427.857 ~'8.427.858) (I) (1, lnlongilllM ~no cm. )0) s 84,290 ( ,..... 74,123,«!7 (»1.7&1> 74,523,•07 3.nt.111.- ..... SONI DOCKET NO. l'l)c;DOCQTNO. COlll/'NfY - TUT YEAll l!HO - I- f"""W T.... lllc. -·II T. . Y,_ T-1 (•I ....,._ c-..., ToTmv.., (111 c_, "--- T091YMt T-1- (cl .---- c;- p-- ToC:-.-, (di- 1-1 • (•) Do--1!·- c;o- - 1• c-tn- ,.._ TOllllE- l •I ~l!s- ~&tmpo1qn• 31 1 1,095.007 0111,1113 s 1,711.7!50 s (• 2• .611 1 s 1.217,119 - Pl9nl EqulPfl*'l 312 8,70$,278 M5.- s t.111.23" s {2.02U02) s 7,612.1172 T-Unb 31• 2,"82.980 2.0t5,967 s 4.52U37 s (1. 105,32•) s 3.42).813 ~E-E...,_ 315 2,202.20$ ~.- s 2 ,0&7.1148 s (430,004) s 2.227.944 Milc-P""" Equlp 318 2:ie.oee 118.3811 s 30t•n s (53.073) s 244,588 -Roi-~ 317 (331.958) 331.958 s s s IMoc-Plon!Equlp 338 1188 !9'3l I 2., ! 24~ s-- 14,510,900 • ,301,"80 s 1012 .~ <• .Q.12,4441 s 14.770, 142 l ancl E- l!I02 4Sl.0 58 (M.- ) s 387,302 s s 387.302 --F- ~& lmpl>H+••• 352 • 17.n • (315) s 4 17,..00 s s 4 17.- T_ _ _ , _ s s s -~ ~ 5,3711,875 2.11112,819 8.332.- 8,332.- :!50 418,7 8' "8,647 s 483..• 12 s ( 107,..01 s 3$&.943 :ISO 4, 182,575 779.2. . s • .eet .e11 s s 4,911,119 OH~ &o..ic. 3!1e 2.eeo.200 1,182.083 I 4,022,801 I I 4,022,901 ~~ &o..4oel 350 1.409 5,014 I 8 ,423 I I e.423 Roodo ond Tl9ill 3119 800 2,224 ! 3,0M I I 30M s. - T- 13.722.47• 4.8112.- I 18.-.93" I (107,-) I 18,497,485 l.nd R..,,.. 300 2 240,1153 (30. 1751 210.110 s s 210,778 - S~& l"'P'O't'eiM,.. 381 127.81 1 33,009 180,980 s (9.5121 s 151,"8e -E~ 382 31808.715 383,575 3,970.290 s (391,948) s 3.$70,3"4 - -·- 1,438,l!M 1,247,118 s (1.1'2,011 1 s 7,05$,007 -T--&Fb0ur9o OH C - . & 0.00. *385 8 .IOll.- u oo•.z4 3,U&.758 8.8411, 180 s s 8,MS, 180 ~eo- ~ COnct.lct>n & a.... 387 438,- 2.277.438 :12.S.. 900.810 s ..., 3 2:ie.ose s s I I 1.ne.ose llno T . - - 0 3lle 10~.0Jll 3,08'5.711 I 13,374,720 s (170.ln4) s 12. I07.7IMI OH- 3119 2.rn.:ioe 1.272. 183 I 4.007.- s 280.720 I •.2ee.tao Me.... 370 1.020.813 394.830 I 1,4111,&47 I I 1,416,6'7 ln-on Cu_ P _ 371 558. 199 8 18 I 557.117 I I 557, 117 s - uvnonv 1111c1 51gr111 373 82~ (22,817) ! 40,~ ! 40 0().IO s 4 2,537,348 (2,098,2 73) s 40,039.073 --~ 31.780. 723 10,770.823 R09ioNIT,..,.&MlllOpo- 382 12,125 12,125 12. 125 R09ioNIT,.....&M1110 p o S - 3113 073,827 (8011 873.228 073.220 Strudur'M & lf1t00 wwwt.• •• Ol!lol , . _ & E~ ,,.._~ SloreoEq~ TOOie. Shop, & Gar9ge Equipnent ~E- p,_-o.,.,- Equ- 380 381 Jll2 393 3~ 385 399 - 1,358,298 2.514.230 150.- 550, 547 22,605 30.0.. s • I s I s s s 1272.0tS) 3, 318.550 4'.n • 170.112 88,440 2114.800 {17, 172) s • I I I I •• 1 .087~1 5.&32,707 320.- • 6.879 022.997 217,305 12.012 • s s s s I I I I 1 .007~ 1 5.832. 707 .CS,879 320.- 822,907 277,385 12.872 C~Equ- 387 1.897,918 (JI0.501) 1.3117.477 1,317.•77 t.tlecEqu;pment 3Qe 47 ISS I 123991 I 171, 148 s 1711"8 s.-a...... Plor>t 0,378.274 s 3.38058 s Uo.t.2"2 I 9,704.2•2 ESI ~~ 403 1.990.958 (203,003) 1.m . - (!,130) 1,772.7118 ~e-- 301 735.!lllll S2S."28 I 2'1.Cl27 s 1.2111.(127 ColhAFUOC 303 (1 17.41111 142.IM1 :IS.Jee s 25.350 C.......Acoounllng 303 119,797 111.m 1 172.245 s 172.245 ~cc:s 303 233,924 (51 ,305) 182.819 s 182.819 ~CIS 303 11,389 (1.•37) I 0.~8 s 18.949 c. - . . - 303 117,825 •!Se 118,081 s 118.081 0- 303 240,345 (81.0111 172.334 s 172,334 A&GIMISC 303 2,587,529 {035.744) 1. 751.785 I 1,751. 705 ~GIUISC~R- 303 531.420 (•3.000) 408.A20 s 48e.420 --PTOC!Fuol _ _ PTOO....,.Fuol 303 3,314 (074) 2 ,8 40 s 2 ,&40 303 70t.512 (81,483) 1311.029 s 8.le.029 R_ . i T, _ & Mrtl (RTOllc;n 303 413,575 413'5711 I •1 3.575 r,...,,,.-,,, a OiW1bl.eOn 303 741,llOI ( 173,180) 588.&49 s see...o Tt- 303 ~1R1 'i!i 1~ m e38m 8.440,802 ~--~ 7.0lZ. 171 ($83.389) e .- .802 TOllll~ &Aml M,Nt,111 f2.J7T,M1 ~- 71,G72- (• .-.i1•1 .... ,  ~ SOAH DOCIC!T NO. Catm-IV PUC OOC:Kn NO. T--..n.m COWAllYNAMa TUTv.AAIND _,, f-.,,T•-- .....,.._ ~ .....- ~ ~- ~ ~ ........ ,_ T911lY. . ToT•Y,_ Toon- T-1!!!!!1! To~ !!!!- T-1!!!!!! (•I lb) l•I (di t• I • l•I • ldl TIJIH OTHIR fHAIHIT Non-R- v- r""""°""' AOV-Tu•T- M s- To411P._iy 2 1.831,'30 2DZU.H 23.1'09,e:2t 2.so:!.420 2.592 ..20 2•.22<.lee a.211m 28,301,2'9 (1,380.227) • (t.380,227) •I I 22...... 129 amm 2'-1121.022 ~r ..... 2.287.010 (122.t ..) 2 .1. ..ooe I 157.923) 2. IOll, 173 FICA FUTA :Z0.&30 20,$30 I (51'1 :Z0.011 SVfA aar (122,t .., Hll1 I !! 1711 zzz 1a TQ!alP.,... 2.3'1,"37 2.211,523 I 115.120) 2. 153...a3 F.-,IM T. . . T- 406.33 °'*- I O'*Tuee ESINJV- 281,308 2",308 289.308 ESIP.,...T- 1,913.809 115,3112 1,721,218 1121,5'9) 1,807.- - '°·220 - - ESI frenc:Nilie Tu• .0.220 40,220 ESI°'* 1110 l llO 1fl0 E" " ' V Y - Poyrol T.- 2',319 :1$.llll :1$.llll E"IOrgy~Plyn>IT- ,_,.,,._on..,.p.,... r- 12 12 12 E-VtGIMS_L....,_Pot... 1~721! !~7 !!§1 1~7 SI!• Togj °""' 2.088.530 115.3112 2.201.892 (121.-1 2 .080,3'3 E-- R_...._ S-~A- - T- - 0-0 ~.. T - locol 0-0 R- °"" 13.'2T.19ol 0 19,932.527 ll.5319.7fl0) ( 1.~.lllM) !2.257.«16) 11.ee1.0CM 0- (1.l5e.e&4) 17.875.122 (1,117..10) 1.- .- (l,800,968) 10.m . • 0 02003t6327e I0,0... 1. . E-- E - 1 1... 0 0000000000000 0 020T3019121M7 0 02978732379 Loail Oto. A- •°'* (79.8331 (78.933) 70.133 S-0-.~ · T•- 0 33.Je0,321 (5.227,71121 29,132,529 29,791.752 PUC-E-- 11.- . m1 PUC--T- 1.520,718 320.529 1,IM7,317 (173.590) 1,873. 722 0 o.001ee1 000311322- PUC-·°'* 1mm~1 (a!Q!EJ 212w 1.520.7" 109.796 1,6311.S.. n .1ee 1.en,122 TOTM. TAJCU OTHP 7HAli 83,023,IOI (2.US.tat --.741 (J,174,IOI) 17,e11,J41 INCOMI TAUI t0f»'2012t231PM .....  SOAH DOCKET NO. XXX-XX-XXXX COMM Schedule V PUC DOCKET NO. 38811 Fadenil Income Tax" COMPANY NAME Entltrgy Tex•, Inc. TEST YEAR END 30-Jun-11 FEDERAL INCOME TAXES· METHOD 1 Roq-ted Commluton AIP_... Adjue- Comm...ton THtYHr ToCompony Adjueted TotolElectrtc Reaunt Toto1Elec:1rtc: (c) (d) (•) Retum Total 140,600,598 Lesa: lntereet Included in Retum s 57,409,530 AIT10ltiza1ionol1TC s 1,642,645 Am.,.-tlon ol DFIT (Exceu) s 238,870 ConllOlldallld Tax Savtnga s Plue. s AFUDC s 15,544,523 Other Permanent Differences s (1,720,971) NOf1-Normallzed Timing Dil'ferencee EOllESITaxoe 438,745 Current State Income Tax (37,732) Deferred State Income Tax 64,347 FAS 109 Am.,.-tion ol Exceao DFIT-Depreclation TAXABLE COMPONENT OF RETURN 95,818,485 TAX FACTOR (111· 35X 35) 053&46150 0.§3&46150 TOTAL FIT BEFORE ADJUSTMENTS 51,488,882 Adjustments· Amortization of ITC (1,642,645) Amortization of Excess DFIT • Depreciation (238,870) Prior Yea111 Current FIT Prior Yea111 Deferred FIT EOllESITaxoe 483,745 FAS 109 Other· ConlOlldated Tax Savings TOTAL FEDERAL INCOME TAXES 50,071,092 10/30l2012 12:39 PM Pago& APPENDIX B  SOAH DOCKET NO. f ') PUC DOCKET NO. 39896 1 c. ~. - -._; . iJ P/'J 3: APPLICATION OF ENTERGY TEXAS, § BEFORlfTJW[1~Jf\r~ oi/NcE INC. FOR AUTHORITY TO CHANGE § RATES, RECONCILE FUEL COSTS, § OF AND OBTAIN DEFERRED § ACCOUNTING TREATMENT § ADMINISTRATIVE HEARINGS PROPOSAL FOR DECISION TABLE OF CONTENTS I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4] •.••.••••1 II. JURISDICTION AND NOTICE •.•••••••••••••.•.••••.••••••••.••••..••••..••••.••••.••••.••••.••••••••.•2 III. PROCEDURAL HISTORY •••.•••.••••••••••.•••••••••..•••••••••.•••••••••..••••••••••••••.••••••••••.•••.• 2 IV. EXECUTIVE SUMMARY .......•...•••..•....•.....•....••....•.....•.•.•...•••...•.•...••.•••...•••..•••..4 A. Rate Base •••••••.••••••••••.•••••••••••••••••••.•••••••••••••..•••••.••••••••••••••.••••.•••••••••.••••..••••.•••.•••••••4 1. Capital Investment .....................................................................................4 2. Hurricane Rita Regulatory Asset ............................................................ .4 3. Prepaid Pension Asset Balance ................................................................. 5 4. FIN 48 Tax Adjustment ............................................................................. 5 5. Cash Working Capital ...............................................................................5 6. Self-Insurance Storm Reserve ..................................................................5 7. Coal Inventory ........................................................................................... 5 8. Spindletop Gas Storage Facility ............................................................... 5 9. Short Term Assets ......................................................................................6 10. Acquisition Adjustment. ............................................................................6 11. Capitalized Incentive Compensation ....................................................... 6 B. Rate of Return and Capital Structure .................................................................6 C. Cost of Service ...................................•........•.....•....•...............•......•...•...•....•....•.......7 1. Purchased Power Capacity Expense ........................................................ 7 2. Transmission Equalization (MSS-2) Expense ......................................... 7 3. Depreciation Expense ................................................................................ 7 4. Labor Costs ................................................................................................7 SOAHDOCKET N O . - TABLE OF CONTENTS PAGE TI PUC DOCKET NO. 39896 5. Interest on Customer Deposits .................................................................. 8 6. Property (Ad Valorem) Tax Expense .......................................................9 7. Advertising, Dues, and Contributions .....................................................9 8. Other Revenue Related Adjustments .......................................................9 9. Federal Income Tax ...................................................................................9 10. River Bend Decommissioning Expense .................................................... 9 11. Self-Insurance Storm Reserve Expense ................................................... 9 12. Spindletop Gas Storage Facility ............................................................. 10 D. Affiliate Transactions .......................................................................................... 10 E. Jurisdictional Cost Allocation ............................................................................ 10 F. Class Cost Allocation ........................................................................................... 11 1. Renewable Energy Credit Rider ............................................................ 11 2. Class Cost Allocation ............................................................................... 11 3. Revenue Allocation .................................................................................. 12 4. Rate Design ............................................................................................... 12 G. MISO Transition .................................................................................................. 14 v. RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16] •..•... 14 A. Capital Investment [Germane to Preliminary Order Issue No. 17] ................ 14 B. Hurricane Rita Regulatory Asset ....................................................................... 15 c. Prepaid Pension Asset Balance ...........................................................................23 D. FIN 48 Tax Adjustment .......................................................................................26 E. Cash Working Capital .........................................................................................30 1. The Revenue Lag Component of the Lead-Lag Study ......................... 31 2. The Expense Lead Component of the Lead-Lag Study ....................... 39 F. Self-Insurance Storm Reserve [Germane to Preliminary Order Issue No. 5] .....................................................................................................................45 1. The Effect of Prior Settled Cases........................................................... .46 2. OPC's Proposed Adjustment ................................................................. .49 3. 1997 Ice Storm .......................................................................................... 54 4. Jurisdictional Separation Plan Allocation ............................................. 57 S. $50,000 Reserve Threshold ..................................................................... 59 SOAH DOCKET N O . - TABLE OF CONTENTS PAGEIIl PUC DOCKET NO. 39896 6. Hurricane Rita Regulatory Asset ........................................................... 60 7. Conclusion ................................................................................................ 60 G. Coal Inventory .....................................................................................................61 H. Spindletop Gas Storage Facility .........................................................................63 I. Short Term Assets ................................................................................................68 J. Acquisition Adjustment.......................................................................................69 K. Capitalized Incentive Compensation .................................................................71 VI. RATE OF RETURN [Germane to Preliminary Order Issue Nos. 4 and 11] ..........................................................................................................................73 A. Capital Structure .................................................................................................73 B. Return on Equity .................................................................................................73 1. Proxy Group .............................................................................................74 2. DCF Analysis ............................................................................................ 76 3. Risk Premium Analysis ........................................................................... 83 4. Comparable Earnings ............................................................................. 88 5. · CAPM Analysis ........................................................................................90 6. ALJs' Analysis .........................................................................................93 c. Cost of Debt ..........................................................................................................95 D. Overall Rate of Return ........................................................................................95 VII. OPERATING EXPENSES [Germane to Preliminary Order Issue Nos. 2, 3, 4, and 16) ........................................................................................................... 95 A. Purchased Power Capacity Expense [Germane to Supplemental Preliminary Order Issue No. 1] .......................................................................... 95 1. The Sources of ETl's Purchased Power ................................................95 2. ETl's Request Regarding PPCCs ...........................................................99 3. Staff and Intervenors' Opposition to ETl's PPCCs Proposal.. ......... 101 4. The Intervenors' Recommendations Regarding PPCCs .................... 106 5. The ALJs' Analysis Regarding PPCCs ................................................ 108 B. Transmission Equalization (MSS-2) Expense .................................................110 C. Depreciation Expense [Germane to Preliminary Order Issue No. 12] ..••..••.. 117 1. Terminology and Methodology ............................................................ 118 2. Production Plant .................................................................................... 125 SOAHDOCKETNO.- TABLE OF CONTENTS PAGE IV PUC DOCKET NO. 39896 3. Transmission Plant ................................................................................ 13 2 4. Distribution Plant .................................................................................. 141 5. General Plant. ......................................................................................... 155 6. Fully Accrued Depreciation .................................................................. 160 7. Other Depreciation Issues - Accumulated Provision for Depreciation ........................................................................................... 162 D. Labor Costs ........................................................................................................ 163 1. Payroll and Related Adjustments ......................................................... 163 2. Incentive Compensation ........................................................................ 166 3. Compensation and Benefits Levels ....................................................... 176 4. Non-Qualified Executive Retirement Benefits .................................... 178 5. Employee Relocation Costs ................................................................... 180 6. Executive Perquisites ............................................................................. 181 E. Interest on Customer Deposits .......................................................................... 182 F. Property (Ad Valorem) Tax Expense ............................................................... 182 G. Advertising, Dues, and Contributions ............................................................. 186 H. Other Revenue-Related Adjustments .............................................................. 186 I. Federal Income Tax ........................................................................................... 186 J. River Bend Decommissioning Expense ............................................................ 188 K. Self-Insurance Storm Reserve Expense [Germane to Preliminary Order Issue No. 5] ...................................•............................................................••.......189 L. Spindletop Gas Storage Facility ....................................................................... 195 VIII. AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue No. 3] ................................................................................................................... 195 A. Large Industrial & Commercial Sales Reallocation ....................................... 200 B. Administration Costs .........................................................................................202 c. Customer Service Operations Class .................................................................203 1. Projects F3PCR29324 (Revenue Assurance - Adm.), F3PCR53095 (Headquarter's Credit & Collect), F3PCR73380 (Credit Systems), and F3PCR73458 (Credit Call Outsourcing) ...................................... 203 2. Projects F3PCR73381 (Customer Svc Cntr Credit Desk), F3PCR73390 (Customer Svs Ctl - Entergy Bus), and F3PCR73403 (Customer Issue Resolution - ES) ................................. 204 SOAHDOCKETNO.- TABLE OF CONTENTS PAGEV PUC DOCKET NO. 39896 D. Distribution Operations Class .......................................................................... 205 1. Project FSPCDW0200 (Lineman's Rodeo Expenses) ......................... 205 2. Projects F3PCTJGUSE (Joint Use With Third Party - E) and F3PCTJTUSE (Joint Use With Third Parties - A) ............................ 206 E. Energy and Fuel Management Class ............................................................... 206 1. Project F3PCWE0140 (EMO Regulatory Affairs) ............................. 207 2. Projects F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE004 (SPO Summer09RFP IM & Propslsubmt), and F3PPWET303 (SP02008 Winter Westn RegionRFP-IM) ........................................... 207 3. Project F3PCCSPSYS (System Planning and Strategic) .................... 208 F. Environmental Service Class ............................................................................209 G. Federal PRG Affairs Class ................................................................................211 1. Project FSPPSPE044 (PMO Support Initiative-System) .................... 211 2. Project F3PPUTLDER (Utility Derivatives Compliance) .................. 211 3. Project F3PCSYSRAF (System Regulatory Affairs-Federal)............ 212 H. Financial Services Class ....................................................................................215 1. Projects F3PCF05700 (Corporate Planning & Analysis), F3PCF21600 (Corp Rptg Analysis & Policy), F3PCFF1000 (Financial Forecasting), F3PPADSENT (Analytic/Decision Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs- Entergy) .................................................................................................. 216 2. Projects F3PCF20990 (Operations Exec VP & CFO) and F3PCFF1001 (OCE Support) ................................................................ 217 3. Project F3PCR7334S (Quick Payment Center, Adm) ........................ 218 4. Project F3PCF23936 (Manage Cash) ................................................... 218 I. Human Resources Class ....................................................................................219 1. Project F3PCHRCCSM (HR Competitive Compensation) ................ 220 2. Projects (Non-Qualified Post-Retirement) and FSPPZNQBDU (Non-Qual Pension/Benf-Dom Utl) ....................................................... 220 J. Information Technology Class.......................................................................... 221 1. (Evaluated Receipts Settlement) .......................................................... 221 2. Project F3PCFX3SSS (BOD/Executive Support) ................................ 222 K. Internal and External Communications Class ................................................223 SOAH DOCKET N O . - TABLE OF CONTENTS PAGE VI PUC DOCKET NO. 39896 L. Legal Services Class ...........................................................................................224 1. Project F3PPCASHCT (Contractual Alternative/Cashpo) ................ 224 2. Project FSPCZLDEPT (Supervision & Support - Legal) .................. 224 3. Project F3PCF99180 (Corp. Compliance Tracking Sys) ................... 225 4. Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and F3PPTDHY19 (Dept. of Justice Investigation) ................................... 225 S. Project F3PCE01601 (Ferc - Access Transmission) ...........................228 6. Project F3PCERAKTL (RAKTL Patent Matter) ............................... 229 7. Project F3PPEASTIN (Willard Eastin et al) ...................................... 230 8. Project F3PPTCGS11 (TX Docket Competitive Generation) ............ 231 9. Project FSPCE13759 (Jenkins Class Action Suit)............................... 232 10. Project F3PCSYSAGR (System Agreement-2001) ............................. 233 11. Project F3PCCDVDAT (Corporate Development Data Room) ........ 234 12. Project F3PPWET302 (SPO 2008 Winter Western Region) ............. 235 13. Project F3PPWET308 (SPO Calpine PPA/Project Houston) ............ 236 M. Other Expenses Class ........................................................................................236 1. Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and F5PPKATRPT (Storm Cost Processing & Review) ............................ 237 2. Project F3PCC08500 (Executive VP, Operations) .............................. 237 3. Projects F3PPBFMESI (ESI Function Migration Relocation), F3PPBFRESI (ESI Business Function ), F3PPDRPESI (ESI Disaster Recovery Plan Charge), FSPPBFMREL (Business Function Migration Employee), FSPPBFRREL (Business Function Relocation), F5PPBFRSEV (Business Function Relocation Severance), FSPPDRPREL (Disaster Recovery Plan Relocation), and FSPPETXRFI (2009 Texas Ike Recovery Filing) ... 238 N. Regulatory Services Class .................................................................................240 O. Retail Operations Class .....................................................................................241 1. Project FSPPICCIMG (ICC- "Image" Message) .............................. 241 2. Projects F3PPRS6640 (Wholesale - EGS-TX) and F3PPRS6920 (Wholesale - All Jurisdictions) .............................................................. 242 P. Supply Chain Class ............................................................................................243 Q. Transmission and Distribution Support Class ................................................244 R. Tax Services Class .............................................................................................. 246 SOAHDOCKETNO.- TABLE OF CONTENTS PAGE VII PUC DOCKET NO. 39896 s. Transmission Operations Class ........................................................................247 T. Treasury Operations Class ...............................................................................248 u. Utility and Executive Management Class ........................................................250 IX. JURISDICTIONAL COST ALLOCATION [Germane to Preliminary Order Issue No. 13) ............................................................................................252 A. A&E 4CP ............................................................................................................253 B. 12CP ....................................................................................................................254 x. CLASS COST ALLOCATION AND RATE DESIGN [Germane to Preliminary Order Issue No. 1] ........................................................................256 A. Renewable Energy Credit Rider [Germane to Preliminary Order Issue No. 19] .................................................................................................................257 1. ETl's Proposed Cost Recovery ............................................................. 257 2. Opposition to ETl's Proposal ............................................................... 258 3. ETl's Response ....................................................................................... 262 4. ALJs' Analysis ....................................................................................... 263 B. Class Cost Allocation [Germane to Preliminary Order Issue No. 14] ••••..••.•264 1. Municipal Franchise Fees ..................................................................... 264 2. Miscellaneous Gross Receipts Taxes .................................................... 269 3. Capacity-Related Production Costs ..................................................... 270 4. Transmission Costs ................................................................................ 275 C. Revenue Alloc.ation ............................................................................................276 1. Argument for Moving Rates to Cost .................................................... 277 2. Argument for Gradualism .................................................................... 280 3. ALJs' Recommendation ........................................................................283 D. Rate Design [Germane to Preliminary Order Issue Nos.15, 18, and 20] .....284 1. Lighting and Traffic Signal Schedules ................................................ 285 2. Demand Ratchet. .................................................................................... 289 3. Large Industrial Power Service (LIPS) ............................................... 297 4. Schedulable Intermittent Pumping Service (SIPS) ............................ .301 5. Standby Maintenance Service (SMS) .................................................. .305 6. Additional Facilities Charge (AFC) ..................................................... 312 7. Large General Service (LGS) ............................................................... 314 SOAH DOCKET N O . - TABLE OF CONTENTS PAGE VIII PUC DOCKET NO. 39896 8. General Service (GS) ............................................................................. 317 9. Residential Service (RS) ....................................................................... .317 XI. FUEL RECONCILIATION [Germane to Preliminary Order Issue Nos. 21-31] ..........................................................................................................321 A. Spindletop Gas Storage Facility ....................................................................... 326 B. Use of Current Line Losses for Fuel Cost Allocation .....................................327 c. ETl's Special Circumstances Request .............................................................328 XII. OTllER ISSUES ................................................................................................329 A. MISO Transition Expenses [Germane to Preliminary Order Issue Nos. 6-8 and Docket No. 39741 Preliminary Order Issue Nos.1-9] ..............329 1. Deferred Accounting .............................................................................. 331 2. Base Rate Recovery ............................................................................... 338 B. TCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2] ...................................................................................................................340 c. DCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2] ...................................................................................................................341 D. Purchased Power Capacity Cost Baseline [Germane to Supplemental Preliminary Order Issue No. 1] ........................................................................ 341 XIII. CONCLUSION .................................................................................................. 343 XIV. PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND ORDERING PARAGRAPHS ...........................................................................344 A. Findings of Fact ..................................................................................................344 B. Conclusions of Law ............................................................................................367 c. Proposed Ordering Paragraphs .......................................................................369 List of Acronyms and Defined Terms Attachment A  List of Acronyms and Defined Terms TERM DEFINITION 12CP 12 Coincident Peak A&E4CP A verag_e and Excess, 4 Coincident Peak A&P Average and Single Coincident Peak AD FIT Accumulated Deferred Federal Income Tax AFC Additional Facilities Char_ge AFUDC Allowance for Funds Used During Construction AUs Administrative Law Judges BCIJJU3 Big Cajun II, Unit 3 Brazos Brazos Electric Cooperative, Inc. Calpine Calpine Energy Services Contract for the purchase of 485 MW of capacity from Carville Contract Calpine's Carville Energy Center CAPM Capital Asset Pricing Model CenterPoint CenterPoint Energy Houston Electric, LLC CGS Competitive Generation Service CI Conformance Index Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and Cities West Orange, Texas Commission Public Utility Commission of Texas Company Entergy Texas, Inc. CP Coincident Peak CWIP Construction Work in Pro_gress DCF Discounted Cash Flow DCRF Distribution Cost Recovery Factor DOE United States Department of Energy DOJ United States Department of Justice EAI Entergy Arkansas, Inc. EAWBL 2009 Contract between ETI and EAI for Wholesale Base Contract Load Resources EGSI Entergy Gulf States, Inc., predecessor to ETI EGSL Entel'gy_ Gulf States Louisiana, LLC ELL Entergy Louisiana, Inc. EMI Entergy Mississippi, Inc. Long-term Gas Supply Contract between ETI and Enbridge Enbridge Contract Pipeline, L.P. ENOl Entergy New Orleans, Inc. Entergy Entergy Coi'Q_oration TERM DEFINITION ESI Entergy Services, Inc. ETEC East Texas Electric CooQ_erative, Inc. ETI Entergy Texas, Inc. FAS 106 F ASB Statement No. 106 FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission FIN48 Financial Int~rpretation Number 48 GAAP Generally Accepted Accounting Principles GDP Gross Domestic Product GS General Service GSU Gulf States Utilities Company Iowa Curves Various Known Patterns of Industrial Asset Mortality Rates IRS Internal Revenue Service ISB Intra-System Bill Class action lawsuit filed in Texas district court in 2003 on Jenkins Class behalf of all Texas retail customers served by ETI's Action predecessor-in-interest, EGSI Kroger The Kroger Co. kW Kilowatt kWh Kilowatt-hour LED Light Emitting Diode LGS Large General Service LIPS Large Industrial Power Service MFF Municipal Franchise Fees MGRT Miscellaneous Gross Receipts Tax MISO Midwest Independent Transmission System Operator, Inc. MSS-2 Schedule MSS-2 of the Entergy System Agreement MW Me_g_awatt Moody's Moody's Investors Service MWh Megawatt-hour NARUC National Association of Regulatory Utility Commissioners Nelson Nelson 6, a 550 MW Unit located in Westlake, Louisiana O&M Operations and Maintenance OATT Open Access Transmission Tariff OPC Office of Public Utility Counsel PFD Pro_Q_osal for Decision PPCCs Purchased Power Capacity Costs PPR Purchased Power Rider PUC Public Utility Commission of Texas PURA Public Utility Regulatory_ Act Rate Year June 1, 2012, through May 31, 2013 Reconciliation Period July1,2009,throughJune30,2011 TERM DEFINITION RECs Renewable Energy Credits Reserve Strategic Petroleum Reserve River Bend River Bend Nuclear Generating Station Unit No. 1 ROE Return on Equity RRC Railroad Commission of Texas RS Residential Service RTO Regional Transmission Or~anization S&P Standard & Poor's SFAS Statement of Financial Accounting Standards SIPS Schedulable Intermittent Pumping Service SMS Standby Maintenance Service SOAH State Office of Administrative Hearings Spindletop Facility Spindletop Gas Storage Facility SRMPA Sam Rayburn Municipal Power Agency Staff Staff of the Public Utility Commission of Texas State Agencies State of Texas State Agencies T&D Transmission and Distribution TCRF Transmission Cost Recovery Factor Test Year July 1, 2010, through June 30, 2011 TIEC Texas Industrial Energy Consumers Value Line Value Line Investment Survey Wal-Mart Wal-Mart Stores, LLC, and Sam's East, Inc. Zacks Zacks Investment Service  SOAH DOCKET NO. PUC DOCKET NO. 39896 APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE INC. FOR AUTHORITY TO CHANGE § RATES, RECONCILE FUEL COSTS, § OF AND OBTAIN DEFERRED § ACCOUNTING TREATMENT § AD1\1INISTRATIVE HEARINGS PROPOSAL FOR DECISION I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4] Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail service area located in southeastern Texas. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI served approximately 412,000 Texas retail customers. The Federal Energy Regulatory Commission (FERC) regulates ETI's wholesale electric operations. On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed increase in annual base rate revenues of approximately $111.8 million over adjusted revenues for the period beginning July l, 2010, and ending June 30, 2011 (Test Year); (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities accompanying ETI' s application and including new riders for recovery of costs related to purchased power capacity and renewable energy credit requirements; (3) a request for final reconciliation of ETI's fuel and purchased power costs for the reconciliation period from July 1, 2009, to June 30, 2011 (Reconciliation Period); and (4) certain waivers to the instructions in Rate Filing Package Schedule V accompanying ETI's application. The rate year for ETI's proposed changes is June 1, 2012, through May 31, 2013 (Rate Year). 1 On April 13, 2012, adjusted its request for a proposed increase in annual base rate revenues to approximately $104.8 million over adjusted Test Year revenues. 1 During the hearing the parties used the term "Rate Year" to refer to the period June 2012 through May 2013. This was intended to represent the first 12 months of the rates adopted in this case. However, the rates in this case will not go into effect (as temporary rates) until at least June 30, 2012. Nevertheless, for purposes of this PFD, Rate Year will refer to the period June 2012 through May 2013. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE2 PUC DOCKET NO. 39896 II. JURISDICTION AND NOTICE The Public Utility Commission of Texas (Commission or PUC) has jurisdiction over ETI and this rate case application pursuant to Public Utility Regulatory Act (PURA) §§ 14.001, 32.001, 33.002, and 35.004. The State Office of Administrative Hearings (SOAH) has jurisdiction over the contested case hearing, including the preparation of the proposal for decision (PFD) pursuant to PURA§ 14.053 and Tex. Gov'tCode§ 2003.049(b). Those municipalities inETI's service areathat have not surrendered jurisdiction to the Commission continue to have exclusive original jurisdiction over ETI' s rates, operations, and services in their respective municipalities pursuant to PURA § 33.001. When ETI filed its application with the Commission, it also filed the application with its original jurisdiction cities. Pursuant to PURA§§ 32.00l(b), 33.051, and 33.053, ETI appealed the actions of the original jurisdiction cities to the Commission and had those appeals consolidated with this docket. ETI' s notice of its application and notice of the hearing were not contested and, therefore, do not require further discussion but will be addressed in the proposed findings of fact and conclusions of law. III. PROCEDURAL HISTORY As noted above, ETI filed its application and rate filing package on November 28, 2011. On November 29, 2011, the Commission referred this proceeding to SOAH. On December 19, 2011, the Commission issued its Preliminary Order setting forth 31 issues to be addressed in this proceeding. On January 19, 2012, the Commission issued a Supplemental Preliminary Order listing two additional issues to be considered and stating that ETI' s request for a purchased power cost recovery rider should not be addressed in this docket. On September 2, 2011, ETI filed an application requesting authority to defer accounting related to its proposed transition to membership in the Midwest Independent Transmission System Operator, Inc. (MISO). This proceeding was docketed as Docket No. 39741. On November 22, 2011, the Commission issued its Preliminary Order in Docket No. 39741 addressing certain SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE3 PUC DOCKET NO. 39896 threshold legal/policy questions and setting forth nine issues to be addressed in the proceeding. On December 20, 2011, Docket No. 39741 was consolidated into this docket for all purposes. The following entities were granted intervenor status in this case: Texas Industrial Energy Consumers (TIEC); State of Texas State Agencies (State Agencies); Office of Public Utility Counsel (OPC); the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange (Cities); The Kroger Co. (Kroger); Wal-Mart Stores, LLC, and Sam's East, Inc. (Wal-Mart); East Texas Electric Cooperative, Inc. (ETEC); and the United States Department of Energy (DOE). The hearing on the merits convened before SOAH Administrative Law Judges (ALJs) Thomas H. Walston, Steven D. Arnold, and Hunter Burkhalter on April 24, 2012, and continued through May 4, 2012. The record remained open for the filing of post-hearing briefs and proposed finds of fact and conclusions of law. On June 8, 2012, the parties filed proposed finds of fact and conclusions of law and the record closed. As permitted byP.U.C. PROC. R. 22.261(a), AU Lilo D. Pomerleau read the record and joined in writing the PFD. Number running began on June 26, 2012, and Staff returned the final numbers to the AU s on July 3, 2012. The parties requested that the AUs submit their PFD so the Commission could consider the matter at its July 27, 2012, open meeting. The following is a list of the parties who participated in the hearing and their counsel: PARTIES REPRESENTATIVES ETI Steven H. Neinast, Casey Wren, and John F. Williamsi Cities Daniel J. Lawton, Stephen Mack, and Molly Mayhall TIEC Rex. D. VanMiddlesworth, Meghan Griffiths, and James Nortev State of Texas Susan Kelley OPC Sara J. Ferris DOE Steven A. Porter Kroger Kurt J. Boehm 2 Several other attorneys appeared on behalf ofETI. The ALJs listed only the three attorneys who appeared throughout the hearing. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE4 PUC DOCKET NO. 39896 PARTIES REPRESENTATIVES Wal-Mart Rick D. Chamberlain Staff Scott Smyth, Joseph Younger, Jacob J. Lawler, and Jason Haas IV. EXECUTIVE SUMMARY ETI proposed an overall increase of approximately $104.8 million. The AUs recommend an overall rate increase for ETI of $16.4 million, as shown on the schedules attached to this PFD. With respect to ETI' s request to reconcile fuel and purchased power costs during the Reconciliation Period, the AU s recommend approval without change. Attachment A contains the schedules provided by Commission Staff reflecting the ALls' recommendations. On issues of particular significance, the AUs' recommendations are set forth below. A. Rate Base 1. Capital Investment ETI's capital additions closed to plant in service between July 1, 2009, and June 30, 2011, were prudently incurred and are used and useful in providing service to ETI's customers. 2. Hurricane Rita Regulatory Asset The appropriate calculation of the Hurricane Rita regulatory asset should begin with the amount claimed by ETI in Docket No. 37744,3 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. This produces a remaining balance of$15,175,563, which should remain in rate base as a regulatory asset, applying a five-year amortization rate that commenced August 15, 2010. Further, the Hurricane Rita regulatory asset should not be moved to the storm insurance reserve. 3 Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGES PUC DOCKET NO. 39896 3. Prepaid Pension Asset Balance The construction work in progress (CWIP)-related portion of ETI's pension asset ($25,311,236 out of the total asset) should be excluded from the asset, but accrue allowance for funds used during construction. 4. FIN 48 Tax Adjustment The Commission should find that $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 Internal Revenue Service (IRS) for the FIN 48 Liability) should be added to ETI's ADFIT and thus be used toreduceETI'srate base. 5. Cash Working Capital The AU s recommend no changes to ETI' s cash working capital. 6. Self-Insurance Storm Reserve The Commission should approve ETI' s Test Year-end storm reserve balance of negative $59,799,744. 7. Coal Inventory The full value of ETI's coal inventory was reasonable and should be included in rate base. 8. Spindletop Gas Storage Facility The Spindletop Gas Storage Facility (Spindletop Facility) is a used and useful facility providing reliability and swing flexibility to ETI' s customers at a reasonable price and should be included in rate base. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE6 PUC DOCKET NO. 39896 9. Short Term Assets The ALls recommend Staffs proposal to include the following amounts in rate base: prepayments at $8,134,351 ($916,313 more than ETI's request); materials and supplies at $29,285,421 ($32,847 more than ETI's request); and fuel inventory at $52,693,485 ($1,066,490 less than ETI' s request). 10. Acquisition Adjustment The $1,127, 778 incurred by ETI in internal acquisition costs associated with the purchase of the Spindletop Facility was reasonable, necessary, properly incurred, and should be included in rate base. 11. Capitalized Incentive Compensation The Test Year for ETI' s prior ratemak:ing proceeding ended on June 30, 2009. The reasonableness ofETI's capital costs (including capitalized incentive compensation) was dealt with by the Commission in that proceeding and is not at issue here. Thus, exclusion of capitalized incentive compensation that is financially-based can only be made 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). B. Rate of Return and Capital Structure The ALls recommend a return on equity (ROE) of 9.80 percent; a cost of debt of 6. 74 percent; a capital structure comprised of 50.08 percent debt and 49 .92 percent common equity; and an overall rate of return of 8.27 percent. This is a downward adjustment to ETI' s request for a 10.60 percent ROE, and no change to ETI's 6.74 percent cost of debt and 50.08/49.92 capital structure. It compares to Staffs proposed 9.60 percent ROE; OPC's proposed 9.30 percent ROE; TIEC's proposed 9.50 percent ROE; Cities' proposed 9.50 percent ROE; and State Agencies' proposed 9.30 percent ROE. No party opposed ETI's proposed 6.74 percent cost of debt or its proposed 50.08/49.92 capital structure. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE7 PUC DOCKET NO. 39896 C. Cost of Service 1. Purchased Power Capacity Expense ETI's purchased power capacity costs should be set at the amount of the Company's Test Year level, which is $245,432,884. 2. Transmission Equalization (MSS-2) Expense ETI should recover only the amount of expenses under Schedule MSS-2 of the Entergy System Agreement it paid in the Test Year, $1,753,797. 3. Depreciation Expense The interim retirements methodology should not be adopted. The values proposed by ETI should be adopted except for the following: Service Lives: Account 364-40 R 1. Account 368-33 L0.5. Net Salvage: Production Plant- negative 5 percent. Account 354-negative 5 percent Account 361-negative 5 percent. Account 362-negative 10 percent. Account 368-negative 5 percent. Account 369.1-negative 10 percent. Account 369.2-negative 10 percent. 4. Labor Costs » Payroll and Related Aqjustments The Commission should accept: (1) the payroll adjustments proposed in theETI application; and (2) the further payroll adjustments proposed by Staff as corrected by ETI. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGES PUC DOCKET NO. 39896 > Incentive Compensation ETI should not be entitled to recover its financially based incentive compensation costs. Thus, the AU s recommend removing $6, 196,03 7 from ETI' s requested operation and maintenance (O&M) expenses. Additionally, an additional reduction should be made to account for the FICA taxes that ETI would have paid as a result of those costs. > Compensation and Benefit Levels ETI met its burden to prove the reasonableness of its base pay and incentive package costs. It is reasonable to view market price for these categories of costs as lying within a range of +/- 10 percent of median, rather than being a single point along a spectrum. As to both base pay and the incentive package, ETI has proven that its costs fall within such an acceptable range. Accordingly, the AlJs recommend rejecting the adjustments sought by Cities. > Nonqualified Executive Retirement Benefits The AlJs recommend an adjustment to remove $2,114,931, representing the full costs associated with ETI' s non-qualified executive retirement benefits. > Employee Relocation Costs The Commission should allow ETI' s relocation expenses. > Executive Perquisites The AlJs recommend an adjustment to remove $40,620, representing the full cost of ETI' s executive perquisite costs. 5. Interest on Customer Deposits The AlJs recommend using the active customer deposits amount of $35,872,476 and the 2012 interest rate, which produces a recommended interest expense of $43,047 ($35,872,476 multiplied by .12 percent). SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE9 PUC DOCKET NO. 39896 6. Property (Ad Valorem) Tax Expense ETI's property tax burden should be adjusted upward by applying the effective tax rate of 0.007435784 for the calendar year 2011 to the final, adopted Test Year-end plant in service value for ETI. 7. Advertising, Dues, and Contributions The AUs recommend an adjustment to remove $12,800 fromETI's costs of advertising, dues and contributions. 8. Other Revenue Related Adjustments These amounts were determined through number running and are reflected in Attachment A. 9. Federal Income Tax The Commission should adopt ETI' s proposal on federal income taxes. 10. River Bend Decommissioning Expense ETI' s annual decommissioning revenue requirement should reflect the most current calculation of $1,126,000. Therefore, an adjustment of $893,000 to the proforma cost of service is needed to reflect the difference between the requested level for decommissioning costs of $2,019,000 and the recommended level of $1,126,000. 11. Self-Insurance Storm Reserve Expense The Commission should approve a total annual accrual of $8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its current deficit. The ALls recommend approval of ETI's proposed target reserve of $17,595,000. The Commission should require ETI to continue recording its annual accrual until modified by future Commission orders. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 10 PUC DOCKET NO. 39896 12. Spindletop Gas Storage Facility The AU s recommend inclusion of the costs of operating the Spindletop Facility as requested byETI. D. Affiliate Transactions ETI agreed to remove the following affiliate transactions from its request, which the AU s recommend be approved: (1) Project F3PPCASHCT (Contractual Altemative/Cashpo) in the amount of $2,553; (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288; and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929. Except as noted below, all remaining affiliate transactions should be approved. The AU s recommend that the following affiliate transactions not be included: $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated with Projects F5PCWBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non Qual Pension/Bent Dom Utl); $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts Settlement); $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al); and $171,032 of costs associated with Project F3PPE9981S (Integrated Energy Management for ESI). E. Jurisdictional Cost Allocation The AUs recommend the use of 12 Coincident Peak (12CP) to allocate capacity-related production costs between the retail and wholesale jurisdictions. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 11 PUC DOCKET NO. 39896 F. Class Cost Allocation 1. Renewable Energy Credit Rider The Commission should deny ETI' s request to institute a renewable energy credit rider, and the Test Year expense of $623,303 should be used for setting rates in this case. Finally, the Renewable Portfolio Standard Calculation Opt-Out Credit Rider should be maintained, with an adjustment to the credit rates to reflect the Test Year data used to set ETI's base rates. 2. Class Cost Allocation The parties generally agreed that ETI's cost-of-service study comported with accepted industry practices, but some parties had issues with specific items discussed below. (a) Municipal Franchise Fees Municipal franchise fees should be allocated on the basis of in-city kilowatt-hour (kWh) sales, without an adjustment for the municipal franchise fee rate in the municipality in which a given kWh sale occurred. The AUs recommend adoption of ETI's proposal to collect costs from all customers taking service from the system. (b) Miscellaneous Gross Receipts Tax Similar to municipal franchise fees, miscellaneous gross receipts taxes should be allocated to the rate classes according to ETI's cost of service study. (c) Capacity-Related Production Costs The AUs recommend the use of Average and Excess 4 Coincident Peak (A&E 4CP) to allocate capacity-related production costs, as proposed by ETI. The AUs do not find sufficient support to allocate the reserve equalization payments differently than other capacity-related production costs. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE12 PUC DOCKET NO. 39896 (d) Transmission Costs ETI' s proposed methodology for allocation of transmission costs should be approved. A&E 4CP is a well-accepted method for allocating such costs. 3. Revenue Allocation Revenue allocation in this case should be based on each class's cost of service and consistent with the AIJs' recommendations in the PFD that impact revenue allocation. 4. Rate Design (a) Lighting and Traffic Signal Schedules ETI should be directed to perform a light emitting diode (LED) lighting cost study before significant changes are made to its lighting rates. The AlJ s further recommend that ETI conduct this study before filing its next rate case and provide the results of any completed study to Cities and interested parties. The study should include detailed information regarding differences in the cost of serving LED and non-LED lighting customers, if ETI currently has LED lighting customers taking service. ETI should modify the applicable tariffs to eliminate its fee for any replacement of a functioning light with a lower-wattage bulb. (b) Demand Ratchet ETI's proposed Large Industrial Power Service (LIPS) tariff should be amended to include the language proposed by DOE witness Etheridge. (c) Large Industrial Power Service The AlJ s recommend the adoption of a $630 customer charge for this customer class, a slight decrease in the LIPS energy charges, and an increase in the demand charges from current rates for this class, as proposed by Staff witness Abbott. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 13 PUC DOCKET NO. 39896 (d) Schedulable Intermittent Pumping Service The Commission should adopt the Schedulable Intermittent Pumping Service rider proposed by DOE witness Etheridge. (e) Standby Maintenance Service The Commission should adopt the changes to Schedule SMS recommended by TIEC, with the exception of a $6,000 customer charge. Consistent with the ALls' recommendation that a new LIPS charge of $630 is reasonable, the Standby Maintenance Service (SMS) charge should be limited to $630 and not apply if a Schedule SMS customer also purchased supplementary power under another applicable rate. (f) Additional Facilities Charge Schedule AFC should be changed in accordance with TIEC's recommendations and those recommended numbers should be reduced in proportion to any authorized reduction in ETI' s proposed rate of return, O&M expense, and property tax expense. (g) Large General Service Schedule LGS should be amended as proposed by Kroger. Schedule LGS also has a demand ratchet, and the ALls' recommendation for the elimination of ETI's LIPS demand ratchet is applicable to this class (h) General Service The Commission should adopt the decrease in the Schedule GS customer charge to $39.91 from the current (and Company proposed) rate of $41.09, as well as Staffs recommended decrease in energy charges. Schedule GS also has a demand ratchet, and the ALls' recommendation for the elimination of ETI' s LIPS demand ratchet is applicable to this class. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE14 PUC DOCKET NO. 39896 (i) Residential Service ETI's declining block winter rates provide a disincentive to energy efficiency. The AUs recommend an initial 20 percent reduction, followed by 20 percent subsequent reductions of the differential in the next three rate cases unless ETI provides sufficient evidence that such changes are unjust and unreasonable. G. MISO Transition The Commission should deny ETI's request for deferred accounting of its MISO transition expenses to be incurred on or after January 1, 2011. However, the Commission should 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. Further, the Commission should authorize ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of the Test Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of $2,452,800. V. RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16] A. Capital Investment [Germane to Preliminary Order Issue No.17] ETI presented for review $408,078,600 in capital additions closed to plant in service between July 1, 2009, and June 30, 2011; that is, from the end of the test year in the Company's last base rate case, which was Docket No. 37744, through the Test Year presented in this case. The capital additions were detailed in the testimony and exhibits of the following Company witnesses: Garrison (Generation), Mcculla (Transmission), Corkran (Distribution), Stokes (Customer Service), Brown (Information Technology), Plauche (Administrative), Cicio (System Planning and Operations), Hunter (Supply Chain), May (Regulatory), and Sloan (Legal).4 The evidence shows that these capital 4 ETI Ex. 27 (Garrison Direct) at 20-28 and WWG-4; ETI Ex. 32 (McCulla Direct) at 64-92 and MFM-16; ETI Ex. 25 (Corkran Direct) at 78-108 and SBC-3; ETI Ex. 37 A (Roman Direct, adopted by Stokes) at 121- 125 and AFR-5; ETI Ex. 24 (Brown Direct) at 29-37 and JFB-3; ETI Ex. 20 (Plauche Direct) at 37-44 and TCP-11; ETI Ex. 39 (Cicio Direct) at 71-75 and PJC-6; ETI Ex. 16 (Hunter Direct) at34-38 and JMH-7; ETI Ex. 7 (May Direct) at 53-54 and PRM-3; and ETI Ex. 38 (Sloan Direct) at 37-43 and RDS-4. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE15 PUC DOCKET NO. 39896 additions were prudently incurred and are used and useful in providing service to ETI's customers. No party challenged any of the capital additions or the costs thereof, and the AU s find no reason to do so either. B. Hurricane Rita Regulatory Asset Hurricane Rita struck the upper Texas coast in September 2005, causing extensive property damage. In 2006, the Texas Legislature enacted PURA Chapter 39 to authorize electric utilities such as ETI to securitize the recovery of their reconstruction costs incurred as a result of Hurricane Rita. Under the statute, the amount of reconstruction costs to be securitized had to be reduced by the insurance proceeds and government grants received by a utility. If additional insurance or grant proceeds were received after the securitization order was approved, the Commission was required to take those amounts into account in the utility's next base rate case. This was provided in Section 39.459(c) of PURA: To the extent a utility subject to this subchapter receives insurance proceeds, governmental grants, or any other source of funding that compensates it for hurricane reconstruction costs, those amounts shall be used to reduce the utility's hurricane reconstruction costs recoverable from customers. If the timing of a utility's receipt of those amounts prevents their inclusion as a reduction to the hurricane reconstruction costs that are securitized, the commission shall take those amounts into account in: (1) the utility's next base rate proceeding; or (2) any proceeding in which the commission considers hurricane reconstruction costs. Docket No. 32907 was the proceeding for ETI to determine the amount of Hurricane Rita reconstruction costs that it could securitize, net of any proceeds received from insurance or 5 government grants. In that case, ETI asserted that it incurred $393,236,384 in Hurricane Rita reconstruction costs for its Texas Retail jurisdiction. The parties reached a settlement in that case, which set ETI's hurricane reconstruction expenses eligible for securitization at $381,236,384. In addition, ETI estimated that it would receive $65,700,000 in future insurance proceeds that, pursuant 5 Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No. 32907 (Dec. 1, 2006). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE16 PUC DOCKET NO. 39896 to the settlement, was deducted from the amount to be securitized. The parties also agreed that after ETI received all of its insurance payments, a true-up would occur to reflect the difference between the $65,700,000 credited and the amount actually received. The settlement agreement provided that if ETI received more insurance payments than estimated, the excess payments would be passed through to ratepayers in the form of a rider; however, the agreement did not address how an under- recovery by ETI would be handled. It turned out that ETI received only $46,013,904 in insurance proceeds,6 leaving a $19 ,686,096 under-recovery by ETI, which the parties refer to as Overestimated Insurance Proceeds. 7 Docket No. 37744 was ETI's next base rate case after Docket No. 32907. In Docket No. 37744, ETI requested recovery of the Overestimated Insurance Proceeds by establishing a regulatory asset of $19,686,096, plus accrued carrying costs, to be amortized over five years. 8 Docket No. 37744 also concluded by a black-box settlement, and neither the Stipulation and Settlement Agreement nor the Order entered by the Commission specifically addressed the proposed regulatory asset or any other recovery for Overestimated Insurance Proceeds. In the present case, ETI has again sought approval of a regulatory asset to recover $26,229,627, for the balance of Overestimated Insurance Proceeds, plus carrying costs through June 30, 2011. 9 Cities objected to the amount of ETI's request. They argue that this issue was resolved in Docket No. 37744 and that ETI should have been amortizing the asset since the conclusion of that case. Staff also argues that the issue was resolved in Docket No. 37744 and requested that ETI' s request be denied entirely; or, alternatively, that it should be considered partially amortized and accordingly reduced. ETI argues that the issue was not resolved in Docket No. 37744 and that it should be allowed a full recovery in the present case. Alternatively, ETI argues that Cities' proposed reduction was not calculated correctly. 6 See Docket No. 32907, Final Order at FoF 27. Cities Ex. 2 (Garrett Direct) at Exhibit MG2.3. $19,686,096 = 65,700,000 - $46,013,904. 7 8 Cities Ex. 2 (Garrett Direct) at l l. 9 Schedule P Cost of Service Workpapers, Vol. 2, ETI Ex. 3 at AJ 15, page 15.3. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE 17 PUC DOCKET NO. 39896 Cities' expert accounting witness, Mark Garrett, testified that ETI should have been amortizing the balance of Overestimated Insurance Proceeds since the effective date of rates set in Docket No. 37744. In addition, he argues that ETI should not have continued to accrue interest on the balance that was added into rate base in that docket, because it would have then earned a rate of return. Therefore, Mr. Garrett's adjustment started with the balance of $25,278,210 that ETI requested in Docket No. 37744. He reduced that balance by $9,479,329 for amortization between the date rates went into effect in Docket No. 37744 and the date that rates will go into effect in the current case (22.5 months). Mr. Garrett further reduced the remaining balance by $5,678,960 to account for additional insurance proceeds received by ETI after Docket No. 37744. By Mr. Garrett's calculations, this left a remaining balance of Overestimated Insurance Proceeds of $11,071,3 3 8. 10 Both Mr. Garrett and Cities witness Jacob Pous also recommended that this remaining balance not be carried as a regulatory asset but, instead, be moved to the storm insurance reserve for recovery. 11 In their view, this would ensure that the remaining balance would be properly recovered. In response to ETI's argument that the Hurricane Rita Regulatory Asset was not resolved in Docket No. 37744, Cities stress that Docket No. 37744 settled as a "black box settlement." In Cities' opinion, such a settlement should not be interpreted as changing the status quo unless expressly stated in the settlement agreement or final order. Cities contend that the status quo in Docket No. 37744 was that ETI was authorized to recover its Over Estimated Insurance Proceeds, because recovery was authorized by PURA § 39 .459(c); recovery had been previously approved in Docket No. 32907; and no party objected to its recovery in Docket No. 37744. Therefore, Cities state, the final order in Docket No. 37744 should be interpreted as authorizing ETI's requested recovery of the Hurricane Rita Regulatory asset in the rates set in that docket. 12 Cities also disagree with ETI' s alternative argument that Mr. Garrett improperly calculated the remaining balance of the asset by deducting an amount for insurance proceeds ETI received after Docket No. 37744 concluded. Cities state that Mr. Garrett's adjustment was correct because it began 10 Cities Ex. 2 (Garrett Direct) at Exhibit MG2.3. 11 Id. (Garrett Direct) at 12; Cities Ex. 5 (Pous Direct) at 64. 12 Cities Reply Brief at 10-14. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 18 PUC DOCKET NO. 39896 with the balance requested in Docket No. 37744, before the additional insurance proceeds were received. In other words, Mr. Garret did not start with the balance claimed by ETI in the present case, 13 so he correctly applied the amount, received after Docket No. 37744 to reduce the balance 14 claimed in that docket. According to Cities, Mr. Garrett began with the prior balance to properly reflect that no carrying charges would accrue on the balance after it was included in rate base and recovered a return through rates. 15 Cities also dispute ETI' s argument that Mr. Garrett should not have accounted for amortization occurring between the Test Year and the Rate Year as an "invalid 16 post-test year adjustment.'' In Cities' view, this was a valid known and measureable change that should be taken into account. 17 Staff recommends that the Hurricane Rita Regulatory Asset be removed from rate base entirely. Staff witness Anna Givens stated that it is reasonable to assume that this asset was included as part of the settlement in Docket No. 37744. Accordingly, she stated that it is not appropriate for ETI to request recovery of the same asset in the present docket. Therefore, Ms. Givens recommended removal of the entire requested $26,229,627 Hurricane Rita regulatory asset from ETI' s rate base. 18 Alternatively, Ms. Givens proposed that the Commission allow ETI a regulatory asset of $17,486,418, to be amortized over 40 months. Ms. Givens noted that higher rates from Docket No. 37744 first went into effect on August 15, 2010; 19 therefore, at least one-third of the regulatory asset should have been amortized by the conclusion of the present case. Using ETI's updated hurricane regulatory asset request of $26,229 ,627, Ms. Givens recommended a decrease of one-third to ETI's request. This would equal an $8,743,209 reduction, resulting in her recommended 13 Cities Initial Brief at 8. 14 Cities Ex. 2B (Garrett Direct), Exhibit MG-2.3. 15 Docket No. 32907, Final Order at FoF 28. 16 ETI' s Initial Briefat 7. 17 Cities' Reply Brief at 10-14. 18 Staff Ex. l (Givens Direct) at 32-34. 19 Docket No. 37744, Order, FoF 16 (Dec. 13, 2010). SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 19 PUC DOCKET NO. 39896 regulatory asset of $17,486,418 ($26,229 ,627 - $8, 743,209). Ms. Givens also recommended that the amortization period be decreased from 60 months to 40 months, which is the time remaining on ETI's original Docket No. 37744 request. 20 ETI disagrees with Cities and Staff, and it argues that its total requested Hurricane Rita regulatory asset should be included in rate base in this case. First, it notes that no instruction in the Stipulation and Settlement Agreement filed in Docket No. 37744 required ETI to begin amortizing the asset or otherwise directed the treatment of the asset. Likewise, no Finding of Fact or Conclusion of Law in the agreed order entered in Docket No. 37744 authorized the proposed treatment of the asset. In contrast, ETI notes, the settlement in Docket No. 32907 does specifically address the treatment of this asset, and it argues that its request to include the full Hurricane Rita regulatory asset in rate base in the present case is consistent with that settlement. In ETI's opinion, it has not previously been authorized to establish the regulatory asset, it has not amortized it, and the full amount should be included in rate base in this case. 21 Alternatively, if Cities' proposed amortization is accepted, ETI argues that Mr. Garrett's calculations were wrong. First, ETI states, Mr. Garrett incorrectly assumed that the $26,229,627 Hurricane Rita regulatory asset requested in this case did not account for the $5,678,960 of insurance proceeds that ETI received after Docket No. 37744. According to ETI, the $5,678,960 was accounted for, as shown on WP/P AJ 15.3. Therefore, ETI states, Mr. Garrett's adjustment for this $5.6 million would remove this amount from the asset a second time. 22 Second, ETI argues that Mr. Garrett erred by amortizing the asset by 22.5 months. Mr. Garrett calculated the amortization period from the time rates went into effect after Docket No. 37744 (August 15, 2010) through the time revised rates would go into effect in this docket (June 30, 2012). ETI states that Mr. Garrett 20 Staff Ex. 1 (Givens Direct) at 34. Ms. Givens noted that amount recommended in Docket No. 37744 was $25,278,000, which is $951,627 less than the amount requested in the current proceeding. However, she stated that this does not affect her recommendation, because by the time the hearing on the merits concluded, at least another two months of amortization expense under the existing rates would be collected by the ETI and should adequately compensate it for the difference. Staff Ex. 1 (Givens Direct) at 35. 21 ETI Ex. 46 (Considine Rebuttal) at 19-24; ETI Initial Brief at 5-6. 22 ETI Ex. 46 (Considine Rebuttal) at 21-22; ETI Initial Brief at 7. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE20 PUC DOCKET NO. 39896 made an invalid post-test year adjustment because post-test year adjustments for rate base items are limited to plant additions recorded in FERC Accounts 101 or 102. In contrast, regulatory assets, like the Hurricane Rita regulatory asset, are recorded in Account 182.3. Therefore, in ETI' s opinion, if it was required to amortize this regulatory asset, it would be appropriate to amortize it for only 10.5 months, to the end of the Test Year (August 15, 2010, through June 30, 2011). These two corrections would adjust Mr. Garrett's proposed asset balance from $10,714,557 to $21,805,940. 23 ETI also disagrees with Mr. Pous' recommendation that the regulatory asset be removed from rate base and placed in the storm reserve, to be amortized over 20 years. In ETI's opinion, this approach would defeat the purpose of securitization, which is to provide ETI with cost recovery in an expedited manner. 24 Finally, ETI argues that Ms. Givens' analysis was flawed. It reiterated that no provision in the Stipulation and Settlement Agreement or the final order filed in Docket No. 37744 directed the treatment of the regulatory asset or stated that ETI would begin amortizing the asset. Further, ETI stresses that it never sought recovery of the entire asset all at once in Docket No. 37744. Instead, ETI requests recovery over a period of years through amortization. Thus, according to ETI, even if Ms. Givens' argument were accepted, the entire asset should not be disallowed. 25 This issue is a close call because the black-box settlement agreement and final order in Docket No. 37744 did not expressly state how the Hurricane Rita regulatory asset issue was resolved. The following factors support finding that the Hurricane Rita regulatory asset issue was resolved in Docket No. 37744: • the settlement agreement and final order in Docket No. 32907 expressly provided that the difference between the amount of ETI's estimated insurance proceeds and the amount actually received by ETI would be trued up after ETI received the proceeds~ 23 ETI Ex. 46 (Considine Rebuttal) at 22; ETI Initial Brief at 7-8. 24 ETI Initial Brief at 8. 25 ETI Ex. 46 (Considine Rebuttal) at 21; Id. at 8-9. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE21 PUC DOCKET NO. 39896 • PURA § 39 .459(c) provides that if the timing of a utility's receipt of insurance proceeds prevented their inclusion as a reduction to the securitized costs, the Commission "shall take those amounts into account ... in the utility's next base rate proceeding;" • Docket No. 37744 was ETI's next base rate proceeding; • in Docket No. 37744, ETI requested a true-up concerning the insurance proceeds, and it requested that a regulatory asset be established for the deficit and amortized over five years; • in Docket No. 37744, no party objected to ETI's proposed regulatory asset or amortization; • the stipulation and settlement agreement entered by the parties in Docket No. 37744 stated that the parties resolved all issues, except for ETr s Competitive Generation Service (CGS) proposal; and • neither the stipulation and settlement agreement nor the Order entered in Docket No. 37744 specifically disapproved, excluded, or deferred consideration ETI' s proposed regulatory asset, although they did specifically exclude or disapprove other items, such as ETI' s CGS proposal and various proposed riders. On the other hand, some factors support a finding that the Hurricane Rita regulatory asset issue was not resolved in Docket No. 37744. The stipulation and settlement agreement and the Order entered in Docket No. 37744 did not expressly approve ETI's proposed regulatory asset, although certain other items were expressly approved, such as River Bend Nuclear Generating Station Unit No. 1 (River Bend) decommissioning costs, depreciation rates, and other items. Also, utilities are typically not allowed to create regulatory assets without express approval of the Commission. Thus, the difficulty with this issue is the nature of the black-box settlement of Docket No. 37744. In the settlement, the parties agreed to an increase in base rate revenues of $59 million effective August 15, 2010, with an additional increase in base rate revenues effective May 2, 2011. However, there was no explanation on how this increase was determined, and there was no specific agreement or finding on the amount of ETI' s rate base or its reasonable and necessary cost of service. In that case, there was no objection to ETI' s proposed Hurricane Rita regulatory asset, it was authorized by the prior settlement in Docket No. 32907, and the Commission was directed by PURA SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE22 PUC DOCKET NO. 39896 § 39 .459(c) to take into account ETI' s insurance proceeds related to the Hurricane Rita securitized costs in ETI's next rate case, which was Docket No. 37744. Moreover, when there is uncertainty whether an undisputed issue was deferred for future consideration or was included within the rates set in a black-box settlement, the burden should be on the utility to establish that the issue was deferred for future consideration. When all the evidence and factors are considered, the AUs find that that ETI's proposed Hurricane Rita regulatory asset should be considered as having been approved in Docket No. 37744, and ETI should have amortized the asset since August 15, 2010, the effective date of rates approved in that docket. The AUs also find that none of the amortization calculations proposed by the parties were entirely correct. ETI's proposal to start with its requested $26,229,627 was flawed because it included carrying costs from August 15, 2010, when the asset should have been included in rate base, to June 30, 2011, the end of the Test Year in the present case. During that period, the asset would have earned a rate of return as part of rate base, and accrual of carrying costs should have ceased. Therefore, it would be more accurate to begin amortizing the Hurricane Rita regulatory asset by using the balance requested by ETI in Docket No. 37744. That amount, according to Mr. Garrett, was $25,278,210. However, the amortization calculation should not extend beyond the end of the Test Year in the present case (June 30, 2011), as proposed by Cities and Staff. P.U.C. SUBST. R. 25 .231 (c )(2)(F)( ii) provides for post-test-year reductions to rate base, and the recommendation for a post-test-year adjustment to the Hurricane Rita regulatory asset does not fall within the scope of that rule. The balance remaining after amortization to the end of the Test Year should be further reduced by $5,678,960 to account for additional insurance proceeds received by ETI after Docket No. 37744 concluded but before the end of the Test Year in the present case. ETI argues that this reduction was already included in its request. However, as discussed above, the appropriate calculation should begin with the balance of the asset at the conclusion of Docket No. 37744, not the balance requested by ETI in the present case. The balance of the asset at the conclusion of Docket No. 37744 did not account for the additional insurance proceeds paid to ETI afterwards, so it should be deducted now. In summary, the AUs find that the appropriate amount of the Hurricane Rita regulatory asset to be included in rate base in this case should be calculated as follows: SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE23 PUC DOCKET NO. 39896 Beginning balance at conclusion of Docket No. 37744 (original balance+ carrying charges) $25,278,210 Less amortization for period 8/15/10 to 6/30/11 = 10.5months160 months= 17.5% - $4,423,687 Less additional insurance proceeds received - $5,678,960 Remaining balance of Hurricane Rita regulatory asset $15,175,563 Finally, the AU s recommend that the Commission not adopt the recommendation of Cities to move the Hurricane Rita regulatory asset to the storm insurance reserve for recovery. As noted by ETI, one purpose of enactment of PURA Chapter 39 was to allow expedited recovery of costs resulting from Hurricane Rita storm damage. Moving the regulatory asset to the storm insurance reserve would defeat that purpose and negate the five-year amortization plan the parties agreed to in Docket No. 37744. In summary, the AU s find that ETI' s proposed Hurricane Rita regulatory asset was an issue resolved by the black-box settlement in Docket No. 37744. Therefore, ETI should have included the asset in rate base at the conclusion of that docket and should have begun amortizing it over a period of five years. The accrual of carrying charges 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. The appropriate calculation of the 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. This produces a remaining balance of $15,175,563, which should remain in rate base as a regulatory asset, applying a five-year amortization rate that commenced August 15, 2010. Further, the Hurricane Rita regulatory asset should not be moved to the storm insurance reserve. C. Prepaid Pension Asset Balance ETI included in rate base an item titled Unfunded Pension in the amount of $55,973,545. 26 The amount requested in this account represents the accumulated difference between the Statement of Financial Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual 26 ETI Ex. 3, Sched. B-1, Line 10. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE24 PUC DOCKET NO. 39896 contributions made by the Company to the pension fund. 27 It is a debit balance, meaning that the Company has contributed roughly $56 million more to its pension fund than the minimum required by SFAS 87. 28 Other than Cities, no party opposes ETI' s request to include this item in rate base. Cities argue that ETI ought not be entitled to include this amount in rate base because it represents amounts the ETI overpaid to its pension, resulting in little to no benefit to ratepayers. Cities witness Mark Garrett pointed out that ETI earned only 1.37 percent on its pension assets over the past five years, while it is seeking a rate of return of more than 11 percent. Thus, he argues, if the asset were included in rate base, ratepayers would pay a substantial premium for the slight pension cost savings ETI' s excess contributions may have achieved. 29 Cities argue that the entire prepaid pension asset should be removed from rate base because ETI has not justified its inclusion. This would reduce pro forrna rate base by $36,382,803, which is the net amount of the prepaid balance less accumulated deferred income tax ($55,973,545 - $19,590,740 = $36,382,803). At the same time, Cities would increase operating expense by $498,284, to provide a 1.37 percent return on the net balance of ETI' s prepaid pension asset balance. 30 Alternatively, Cities contend that the Commission should treat the pension assets in the same manner as the approach adopted by the Commission in Docket No. 33309. 31 In that docket, the Commission allowed a pension prepayment asset, less accrued deferred federal income taxes (ADFIT) and less the portion of the asset that is capitalized to CWIP, to be included in rate base. As to the excluded portion, the Commission allowed the accrual of an allowance for funds used during construction (AFUDC). Thus, Cities contend, if the Commission opts for this approach, it should allow ETI's pension prepayment asset, less ADFIT, to be included in rate base, but excluding 27 Cities Ex. 2 (Garrett Direct) at 7. 28 ETI Initial Brief at 10; Cities Ex. 2 (Garrett Direct) at 8. 29 Cities Ex. 2 (Garrett Direct) at 8-9. 30 Id. at 10, MG-2.2; Cities Initial Brief at 10. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE2S PUC DOCKET NO. 39896 $25,311,236 for the portion of the prepaid pension balance associated with CWIP, and allow AFUDC to accrue on the excluded balance. 32 ETI responds first by disputing Mr. Garrett's contention that it has unreasonably overpaid into its pension fund. It contends it has made contributions to the pension fund in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, and that the contributions were within the allowable range of contributions deductible for tax purposes. ETI also was guided in its required pension contributions by the Pension Protection Act of 2006 rules, effective beginning with the 2008 plan year. 33 ETI next disputes Cities' contention that the earnings associated with ETI's pension contributions provide insufficient benefits to justify inclusion of the asset in rate base. ETI points out that ratepayer benefits are not just limited to the level provided by the actual pension fund earnings on investment. Rather, under FAS 87, pension costs included in the cost of service for ratemaking purposes are intended to include the expected rate of return on assets. Thus, ETI argues that the expected long-term rate of return on ETI' s assets is 8.5 percent, not the actual earnings as suggested by Mr. Garrett. 34 On behalf of ETI, Mr. Considine testified that the pension balance is no different than any other prepayments made by the Company, which are included in rate base and earn a full return on rate base. Furthermore, the Company would be allowed to earn a full return on rate base had the Company invested these same dollars in Plant in Service, but the Company in this case used funds to contribute to a still under-funded pension plan and at the same time provided a timely reduction to formerly FAS 87 annual pension cost, thereby immediateIy benefitting ratepayers. 35 Therefore, ETI 31 Remand ofDocket No. 33309 (Application ofAEP Texas Central Company for Authority to Change Rates), Docket No. 38772, Order on Remand at FoF ISA (Jan. 30, 2011). 32 Cities Initial Brief at 8-9; Cities Ex. 2 (Garret Direct) at 12. 33 ETI Ex. 46 (Considine Rebuttal) at 22. 34 Id. 35 Id. at 23-24. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE26 PUC DOCKET NO. 39896 argues it is clearly investor-supplied capital and accordingly should earn the Company's requested return on rate base. ETI acknowledged the approach to this issue taken by the Commission in Docket No. 33309, but failed to explain why it is distinguishable from the present case. 36 The AUs conclude that the approach taken by the Commission in Docket No. 33309 was sound and should be applied in the present case. Neither party adequately explained why the circumstances of the present case are distinguishable. Thus, the AUs recommend that the CWIP-related portion of ETI' s pension asset ($25 ,311,236 out of the total asset) should be excluded from the asset, but accrue allowance for funds used during construction. D. FIN 48 Tax Adjustment The Financial Accounting Standards Board (FASB) is the body that establishes the rules that constitute generally accepted accounting principles (GAAP). FASB' s Interpretation No. 48 (FIN 48) prescribes the way in which a company must analyze, quantify, and disclose the potential consequences of tax positions that the company has taken which are legally ''uncertain." Pursuant to FIN 48, ETI and its independent auditors are required to evaluate each of its uncertain tax positions to determine, under the most objective, reasonable standards, which portion of each position will most likely ultimately have to be paid to taxing authorities if challenged by the authorities. FIN 48 requires that this portion be excluded from ADFIT for financial reporting purposes and accrue interest and, in some cases, penalties. 37 ETI and its auditors periodically perform the FIN 48 analysis. In so doing, they have concluded that the Company has taken a number of uncertain tax positions that the Company expects to lose if challenged by the IRS. ETI concluded that these uncertain tax positions result in a total of $5,916,461 in tax dollars that the Company expects it will ultimately have to pay, with interest, to the 36 ETI Initial Brief at 10-11. 37 ETI Ex. 70 (Warren Rebuttal) at 9-12. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE27 PUC DOCKET NO. 39896 IRS. As required by FIN 48, this amount is recorded on ETI's balance sheet as a tax liability. 38 In other words, ETI has, thus far, avoided paying to the IRS $5,916,461 in tax dollars (ETI's 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 the IRS. In preparing its application in this proceeding, ETI made an accounting adjustment to its Test Year numbers by not including the $5,916,461 in its ADFIT balance. This had the effect of reducing the Company's Test Year deferred tax balance and, therefore, increasing its rate base. 39 Cities witness Mark Garrrett asserted that the deduction of$5,916,461-representing ETI's FIN 48 Liability - should be added to ETI' s AD FIT balance and thus be used to reduce the Company's rate base. Mr. Garrett pointed out that the Commission first considered this issue in a recent Oncor docket. 40 In that docket, the Commission decided to include FIN 48 liabilities in ADFIT because of the low likelihood that the IRS would actually audit and review the issue. 41 Mr. Garrett testified that this is a fair result because: (1) a utility with FIN 48 liabilities might never have its underlying uncertain tax positions audited by the IRS; and (2) even if the uncertain positions are audited by the IRS, the utility might prevail on them. In either case, the utility would never have to pay those tax amounts. Moreover, during the time when the uncertainty exists, the utility enjoys the use of cost-free capital (from the deferred taxes associated with the deductions) at its disposal. 42 Thus, Mr. Garrett recommends that ETI' s AD FIT balance be increased by $5,916,461 to reinstate the FIN 48 Liability removed by the Company.43 38 ETI Ex. 64 (Roberts Rebuttal) at 4-7. 39 Id. at 4. 40 Cities Ex. 2 (Garrett Direct) at 5-7. See also Application of Oncor Electric Delivery Company LLC for Authority to Change Rates, Docket No. 35717, Order on Reh'g (Nov. 30, 2009). 41 Id. at 18 FOF 59 ("The IRS may not audit or reverse Oncor' s position as to the tax deductions identified as FIN 48 deductions and moved into the FIN 48 reserve."). 42 Cities Ex. 2 (Garrett Direct) at 5-6. 43 Id. at 7. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE28 PUC DOCKET NO. 39896 ETI witnesses Rory Roberts and James Warren stated that the $5,916,461 should not be included in the Company's ADFIT balance. Mr. Roberts explained that, because the Company expects to lose on its uncertain tax positions, it expects that it will ultimately have to pay $5,916,461 in taxes to the IRS, plus interest. Accordingly, Mr. Garrett testified that the amount does not represent cost-free funds available to the Company and, as such, should not be included in the Company's ADFIT balance. 44 Both the Cities and ETI agree that ETI' s rate base "should reflect the actual amount of cost free capital in the ADFIT accounts at Test Year end."45 However, ETI witness Mr. Warren testified that the FIN 48 Liability is not cost-free capital to the Company because the best available expert opinion in the record of this case is that ETI will "most likely" ultimately have to pay the money to 46 the IRS, with interest. Moreover, Mr. Warren pointed out that, beginning with 2010 tax returns, a corporate taxpayer is required to complete and file a Schedule UTP, on which the taxpayer must specifically identify and describe its FIN 48 positions. Mr. Warren contended that, because ETI must now annually file a Schedule UTP, it is more likely that the IRS will audit the Company, thereby forcing it to pay the FIN 48 Liabilities, with interest. 47 This constitutes additional support for the notion that the FIN 48 Liability is not cost-free capital for the Company. Mr.Warren correctly points out that, in a recent CenterPoint Energy Houston Electric, LLC, (CenterPoint) rate case, the Commission specifically acknowledged that filing of a Schedule UTP makes it more likely that a company will be audited. In that case, the ALJs recommended that CenterPoint's FIN 48 Liability, totaling some $164 million, be added to CenterPoint's ADFIT, thereby reducing its rate base. The Commission adopted the recommendation. However, in light of its conclusion that the filing of a Schedule UTP increases the likelihood of an audit, the Commission authorized CenterPoint to establish a deferred tax account rider to enable it to recover any portion of its FIN 48 Liability that it might ultimately be 44 ETI Ex. 64 (Roberts Rebuttal) at 7. 45 Cities Ex. 2 (Garrett Direct) at 6; see also ETI Ex. 70 (Warren Rebuttal) at 6-7. 46 ETI Ex. 70 (Warren Rebuttal) at 17. 47 Id. at 14, 20-21. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE29 PUC DOCKET NO. 39896 forced to pay to the IRS, plus interest. 48 ETI does not necessarily oppose the use of a rider in this case, but contends that it would be preferable to simply exclude ETI' s FIN 48 Liability from its ADFIT balance, thereby increasing its rate base. 49 In the alternative that the Commission rejects ETI' s request to exclude the full amount of the FIN 48 Liability from the Company's AD FIT balance, ETI contends that at least any amount of cash deposit the Company has made with the IRS that is attributable to the FIN 48 Liability should be removed from the Company's ADFIT balance.so The Cities' witness, Mr. Garrett, agrees.st Staff also agrees, arguing that ETI should be required to increase its ADFIT balance by the amount of its FIN 48 Liability less the amount of any cash deposit attributable to the liability that ETI has made with the IRS.s2 ETihas made a cash deposit with the IRS in the amount of$1,294,683. This amount is associated with the Company's FIN 48 Liability.s3 Consistent with prior Commission precedent from the Oncor and CenterPoint proceedings, the AUs conclude that ETI' s FIN 48 Liability should be included in the Company's ADFIT balance. There is, however, one caveat to this conclusion. The amount of the cash deposit made by ETI to the IRS which is attributable to the Company's FIN 48 Liability should not be included in the ADFIT balance. Therefore, the ALls recommend that the Commission find that $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 IRS) should be added to ETI' s ADFIT and thus be used to reduce ETI' s rate base. No party expressly advocated the addition of a deferred tax account rider,s 4 and the AUs do not recommend one in this case. 48 ETI Ex. 70 (Warren Rebuttal) at 19-20. See also Application of CenterPoint Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 38339, Order on Reh' g at 3-4 (June 23, 2011). 49 ETI Initial Brief at 13; ETI Ex. 70 (Warren Rebuttal) at 20. 50 ETI Ex. 64 (Roberts Rebuttal) at 8-9. 51 Cities Ex. 2 (Garrett Direct) at 7 n. 4. 52 Staffs Initial Brief at 11-12. 53 ETI Ex. 64 (Roberts Rebuttal) at 8. 54 Cities and Staff both point out that there is much less need for a deferred tax account rider in the present SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE30 PUC DOCKET NO. 39896 E. Cash Working Capital Rate base includes a reasonable allowance for cash working capital. Cash working capital represents the average amount of investor capital used to bridge the gap in time between when expenditures are made by ETI to provide services and when the corresponding revenues are received by ETI. 55 Generally, an increase in revenue lag days and/or a decrease in expense lead days will result in an increase to the amount of cash working capital included in the rate base. Conversely, a decrease in revenue lag days and/or an increase in expense lead days will reduce the cash working capital included in rate base. A properly prepared lead-lag study can result in either a positive cash working capital amount (and therefore an increase to the rate base) or a negative cash working capital amount (and a corresponding decrease to the rate base). Pursuant to P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), ETicalculated its cash working capital allowance by performing a lead-lag study. ETI witness Jay Joyce prepared the lead-lag study for the Company. Based upon the study, ETI requests a cash working capital addition to its rate base of negative $2,013,921. 56 Only Staff and Cities submitted evidence and argument relevant to the cash working capital requirement. Staff does not challenge the accuracy of the lead and lag days determined in Mr. Joyce's study. Instead, Staff witness Anna Givens recommends that the cash working capital calculation be updated to reflect the impacts of Staffs recommended adjustments to ETI's O&M costs and taxes. 57 ETI agrees that the final cash working capital amount should be updated to reflect the actual revenue requirements approved by the Commission in this case. 58 case than there was in the CenterPoint case, where CenterPoint had $164 million in FIN 48 liabilities. Cities Reply Brief at 18; Staff Reply Brief at l 0. 55 ETI Ex. 17 (Joyce Direct) at 4. 56 Id. at 20 and JJJ-3. 57 Staff Ex. l (Givens Direct) at 30-31. 58 ETI Ex. 54 (Joyce Rebuttal) at 37; ETI Initial Brief at 14. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE31 PUC DOCKET NO. 39896 Cities witness Jacob Pous asserts that Mr. Joyce's lead-lag study contains a number of errors which understate the negative cash working capital requirements of the Company. Mr. Pous asserts that the correct cash working capital amount for inclusion in ETI' s rate base is negative $24,000,000 (more than an order of magnitude increase of the negative amount). 59 Each of the major components of the lead-lag study, and Cities' criticisms of same, will be discussed in tum. 1. The Revenue Lag Component of the Lead-Lag Study Mr. Pous raises a number of criticisms about the revenue lag component of Mr. Joyce's lead lag study. There are four parts to the revenue lag component: (1) the "service period lag," which consists of the roughly 15 days from the mid-point of the month in which service is provided to the end of that month; (2) the "billing lag," which represents the time between the date a customer's meter is read and the date a bill is issued to the customer; (3) the "collection lag," which represents the time between the issuance of the bill and the date the customer's payment is received; and (4) "receipt of funds lag," which measures the delay between ETI's receipt of payment and the bank's clearance of the payment. 60 When the four parts were combined together, Mr. Joyce identified ETI's revenue lag as 43.86 days. 61 (a) Billing Lag Mr. Joyce identified the billing lags (i.e., the delay between when meters are read and bills are sent to customers) as ranging from 5.4 to 5.65 days, depending upon the customer class. 62 On behalf of the Cities, Mr. Pous asserted that this duration is too long. Mr. Pous complained that the billing lag in ETI's lead-lag study is longer than in studies from previous ratemaking proceedings involving ETI' s predecessor, despite the fact that, in the interim between studies, ETI has invested substantially in electronic meter reading devices and computer systems that ought to shorten the lag time. According to Mr. Pous, in a previous proceeding, ETI' s predecessor identified its billing lag as 59 Cities Ex. 5 (Pous Direct) at 72. 60 ETI Ex. 17 (Joyce Direct) at 8-10. 61 Id. at JJJ-3. 62 Cities Ex. 5 (Pous Direct) at 74. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE32 PUC DOCKET NO. 39896 only 3 .61 days. 63 Mr. Pous also pointed out that the Railroad Commission of Texas (RRC), recently adopted a 1-day billing lag for a large gas utility, Atmos Mid-Tex, due to the utility's use of modem electronic meter reading devices (the Atmos Mid-Tex RRC proceeding). Mr. Pous stated that the billing lag identified by ETI would oojustly reward the Company for being inefficient in sending out its bills because customers should not be pooished if the utility decides to manage its billing processing and payment system less efficiently. Thus, Mr. Pous recommended a schedule of different billing lags for different customer classes. For residential and commercial customers, Mr. Pous recommended a 1.46 day billing lag, based since ETI' s predecessor claimed such a lag in a prior PUC docket (Docket No. 12852). For large industrial, public authority, and street lighting customers, Mr. Pous recommends a billing lag of 3.72 days. He calculated that the combined impact of these adjustments would result in a 41.10-day total revenue lag (as compared to Mr. Joyce's figure of 43.86 days). Mr. Pous then calculates that this shorter lag period results in an additional negative cash working capital of $11.4 million. 64 ETI responds by pointing out that the 1.46-day billing lag suggested by Mr. Pous for residential and commercial customers was derived from a rate case by ETI' s predecessor from 1993, whereas Mr. Joyce more properly relied on actual Test Year data. Mr. Joyce asserted that Mr. Pous, in effect, "cherry picked" the 1.46-day figure from one page of a 4 7-page study associated with the 1993 rate case, and that the remaining pages of the study have not been located and, therefore, cannot be evaluated. Thus, Mr. Joyce testified, "[i]t is unfair and unreasonable to use such an old document to attempt to support a position when reasonable, contemporaneous evidence exists."65 ETI argues that it is more appropriate in this case to rely upon ETI's actual residential and commercial billing practices, rather than to substitute artificial and arbitrary 1.46-day and 3.72-day periods derived from other sources. According to Mr. Joyce, it is unavoidably necessary, when conducting a lead-lag study, to take into account the actual amount of time employed by ETI in performing all of the activities in its billing-cycle-based meter reading and billing processes. 63 Id. 64 Id. at 75-77. 65 ETI Ex. 54 (Joyce Rebuttal) at 11. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE33 PUC DOCKET NO. 39896 Mr. Joyce complains that Mr. Pous' approach would jettison this actual data and analysis derived from the Test Year and improperly substitute arbitrary numbers based upon a prior, dated, rate proceeding. 66 Mr. Joyce acknowledged that the RRC recently adopted a 1-day billing lag in the Atmos Mid-Tex RRC proceeding. He pointed out, however, that the RRC did so simply because Atmos Mid-Tex failed to present evidence supporting a longer billing lag. Additionally, Mr. Joyce pointed out that the RRC promptly reversed itself in Atmos Mid-Tex's next rate case, adopting a longer billing lag after the company provided sufficient evidence to support the longer period. 67 ETI also provided extensive evidence regarding the details of its meter reading and billing process. 68 ETI witness Dolores Stokes explained that the meter reading and billing cycle includes time for extensive quality assurance activities to ensure accurate billing, thereby preventing unnecessary frustration for the customer and additional costs to the Company that would be required for customer service, rebilling, and account corrections. 69 Cities questioned Mr. Joyce at the hearing about the billing lag period in this case compared to ETI' s last rate case. Mr. Joyce explained that the total period from meter reading to collection of billing revenues had not changed appreciably between the two cases, but due to a difference in lead- lag methodology, the date that divides the two components of that lag - metering to billing and billing to collection had changed. 70 As a result, the first period - billing lag- was longer than in the previous case but the second period - collection lag - was shorter.71 ETI introduced into evidence a response to a Cities RFI that discussed this difference in more detail. 72 After explaining 66 Id. at 5-7. 67 Id.at 8-9. 68 ETI Ex. 54 (Joyce Rebuttal); ETI Ex. 66 (Stokes Rebuttal). 69 ETI Ex. 66 (Stokes Rebuttal) at 18. 70 Tr. at 499-500, 502. 71 Tr. at 499-502. 72 ETI Ex. 73. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE34 PUC DOCKET NO. 39896 the change in lead-lag methodology, the RFI response concluded that "the combined billing and collection lags are substantially similar from the prior case to this current case."73 The AU s conclude that ETI has met its burden to show that the billing lag it utilized in the lead-lag study is reasonable and appropriate. Absent his own opinion, Mr. Pous does not offer meaningful evidence to support his assertion that the Company's billing lag is too long or that the Company's billing practices are inefficient. For example, he offered no criticism of any specific billing practice of the Company. The only support for his charge of inefficiency is that the billing lag in a previous ETI rate case was shorter. Mr. Joyce convincingly explained that this was merely an artifact of changes in the methodology of the lead-lag study-the billing lag became longer, but the collection lag became shorter. Mr. Pous' reliance upon an example from the RRC is unconvincing. Similarly, his reliance upon data from a previous rate case is unpersuasive, especially because only a very limited snippet of data from that case is available, the case occurred roughly 20 years ago, and it involved a different company. It is not possible, from the evidence in the record, to know how different or similar ETI' s current billing practices are to those used in the previous case. In this case, ETI has thoroughly explained its metering and billing processes and established that those processes are reasonable. The Company is therefore entitled to establish rates based on the actual cash working capital necessary to facilitate those policies. The AI.Js recommend rejecting Cities' request to shorten the billing lag time identified in ETI's lead-lag study (b) Collection Lag In his lead-lag study, Mr. Joyce identified various collection lags (i.e., the delay between the issuance of an electric bill and the date the customer's payment is received) for different classes of customers. As to third-party customers, the collection lag was determined using a random sample of invoices from residential, commercial, industrial, public authority, and street light customer billings 73 ETI Ex. 73 at 2. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE35 PUC DOCKET NO. 39896 during the Test Year, measuring the time between when the bills were mailed and the payment receipt date. The collection lag for MSS-4 and Intra-System Bill (ISB) revenues was based on the 74 actual payment dates for each of the affiliate revenue types. > Collection Lag for Residential Customers As to the residential class, Mr. Joyce determined that the collection lag was 23.73 days. On behalf of the Cities, Mr. Pous disputed the accuracy of that estimate, complaining that it is substantially longer than the lag identified for commercial customers. Mr. Pous contended that Mr. Joyce determined the collection lag for residential customers by relying on a sample size that was too small. Mr. Pous examined the month-end accounts receivable data for ETI's entire residential class for the entire Test Year, and concluded that the collection lag for the class is actually 22.07 days (as compared to Mr. Joyce's figure of 23.73 days). Mr. Pous then calculated that this 75 shorter lag period results in an additional negative cash working capital of $2.4 million. Mr. Joyce made several points in response. First, he noted that, although Mr. Pous is advocating reliance upon month-end accounts receivable data to calculate the collection lag in this case, he has testified in another proceeding that such data is unusable and unreliable. For example, in the Atmos Mid-Tex RRC proceeding, Mr. Pous argued in favor of measuring actual bill payment practices of actual customers (i.e., the approach taken by Mr. Joyce in the present case) and against analyzing the monthly accounts receivable balances for each month of the Test Year (i.e., the approach now being advocated for by Mr. Pous). 76 Next, Mr. Joyce disputed Mr. Pous' assertion that the sample size used by Mr. Joyce was too limited. According to Mr. Joyce, his sample of 100 residential customers is comparable to all of the residential collection lag calculations he has performed during his 15 years of performing lead-lag studies. 77 Mr. Joyce also accused Mr. Pous of 74 ETI Ex. 17 (Joyce Direct) at 10. 75 Cities Ex. 5 (Pous Direct) at 77-79. 76 ETI Ex. 54 (Joyce Rebuttal) at 13-15. 77 Id. at 15-17. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE36 PUC DOCKET NO. 39896 inexplicably picking out a few data points, rather than relying upon the entirety of the sampling data, in order to derive his collection lag estimate.78 The AU s are unpersuaded by Mr. Pous' criticisms and conclude that ETI has met its burden to show that the collection lag it utilized in the lead-lag study for residential customers is reasonable and appropriate. };> Collection Uig for MSS-4 and ISB Affiliate Rate Classes As to MSS-4 and ISB rate classes, Mr. Joyce determined that the collection lags were 46.19 and 15.61 days, respectively. 79 Mr. Pous again disputed the accuracy of these estimates. Mr. Pous pointed out that the underlying data reveals that the majority of the MSS-4 revenue lag days range from 43 to 46 days, with only two values equaling or exceeding 50 days. Mr. Pous testified that the two values equaling or exceeding 50 days should be deemed unrepresentative and, therefore, excluded from the calculations for determining the average lag. Similarly, the majority of ISB revenue lag days range from 15 to 16 days, with only a few lags running as long as 22 days. Again, Mr. Pous contended that the longer revenue lag days should be deemed unrepresentative and excluded from the calculations for the average. Mr. Pous also complained that the payment deadlines for these affiliate transactions are stipulated in the Entergy System Agreement. Thus, it is Mr. Pous' opinion that ETI unreasonably contractually agreed to "excessively long" revenue lag days associated with the MSS-4 and ISB rate classes. Mr. Pous concluded that if what he considers to be the unrepresentative lag days are excluded from the calculations, then the collection lag would change for the MSS-4 class from 46.19 days to 45.14 days, and for the ISB class from 15.61 days to 14.77 days. Collectively, the lag for the two classes would be .77 days shorter, resulting in an additional negative cash working capital of $3. 2 million. 80 78 Id. at 17. 79 Id. at 18. ° Cities Ex. 5 (Pous Direct) at 79-81; ETI Ex. 54 (Joyce Rebuttal) at 18. 8 SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE37 PUC DOCKET NO. 39896 Mr. Joyce first responded by disputing Mr. Pous' contention that there are unusual outliers in the MSS-4 and ISB payment data. He noted that the lag days for MSS-4 payments ranged from 43 to 54 days. He described this as a "relatively tight payment range and certainly within the expected range of reasonableness." 81 Next, Mr. Joyce described Mr. Pous' assertion that outlier numbers should not be considered in the data as nonsensical. Mr. Joyce agreed that, in cases where sampling is used (such as was done for the residential customer class), it is appropriate to exclude data points that are unrepresentative of the population as a whole. In the case of the MSS-4 and ISB classes, however, Mr. Joyce determined the collection lag by reviewing the entire class populations. According to Mr. Joyce, it is inappropriate to eliminate data points when reviewing an entire population, unless it is necessary to make a known and measurable change. 82 The AUs are again unpersuaded by Mr. Pous' criticisms. The AUs conclude that ETI has met its burden as to show that the collection lag it utilized in the lead-lag study is reasonable and appropriate. (c) Receipt of Funds Lag In the lead-lag study, Mr. Joyce identified the receipt of funds lag (i.e., the delay between the date the funds are received from the customers and the date the funds clear the bank and are available toETI). As required byP.U.C. SUBST. R. 25.23l(c)(2)(B)(iii)(IV)(-d-), Mr.Joyce assumed that one business day is needed to clear any payments by methods other than electronic transfer, while electronic payments are available to ETI on the date received. Because 53.39 percent of customer payments were made by methods other than electronic transfer, Mr. Joyce calculated the receipt of funds lag to be .77 days. 83 Mr. Pous again contended that this duration is too long. He acknowledges that P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(N)(-d-) mandates the assumption that funds paid by check will be 81 ETI Ex. 54 (Joyce Rebuttal) at 19. 82 /d.atl9. 83 ETI Ex. 17 (Joyce Direct) at l 0. The receipt of funds lag is also sometimes referred to by the witnesses as the "cash receipts float." SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE38 PUC DOCKET NO. 39896 available "no later than" the following business day. However, he stated that this is merely the maximum possible duration, and ETI should take into account that fact that many checks are cleared (and therefore the funds are available) sooner than one day later. Therefore, the funds from all checks received on any day other than Saturday should be assumed to be available on the date of receipt, while the funds from checks received on Saturday should be assumed to be available two days later. Mr. Pous was also critical of the fact that Mr. Joyce treated the funds from all "walk-in" payments made by customers to be available the next day. Funds from walk-in payments ought to be deemed available on the date they are received. If these two changes are adopted, Mr. Pous contended that receipt of funds lag would be shortened from .77 days to .15 days, resulting in an additional negative cash working capital of $2.1 million. 84 Mr. Joyce first responded by pointing out that Mr. Pous' contention that all funds are immediately available except for checks received on Saturdays is simply not accurate. Mr. Joyce cited from a 2007 Report to Congress made by the Board of Governors of the Federal Reserve System which supports the conclusion that most funds paid by check in this country are not available on the day they are received (and a significant portion are still not available the next business day). 85 Mr. Joyce also disagreed with Mr. Pons' contention that all walk-in payments should be considered immediately available. According to Mr. Joyce, walk-in payments are made at third-party vendor locations, such as grocery stores and check-cashing stores. Based upon his own investigation, Mr. Joyce determined that walk-in payments are actually available to ETI two days after receipt. Thus, his one-day assumption for walk-in payments is conservative. 86 The AU s conclude that ETI has met its burden as to show that the receipt of funds lag it utilized in the lead-lag study is reasonable and appropriate. The positions taken by Mr. Pons on this issue were unreasonable and counter to the requirements of P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-d-). 84 Cities Ex. 5 (Pous Direct) at 81-82; Cities Ex. 5A (Errata No. l). 85 ETI Ex. 54 (Joyce Rebuttal) at 21-23. 86 ETI Ex. 54 (Joyce Rebuttal) at 23-24. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE39 PUC DOCKET NO. 39896 2. The Expense Lead Component of the Lead-Lag Study For the expense lead portion of his lead-lag study, Mr. Joyce calculated different expense lead days for numerous different categories of expenses. Each category will be discussed in tum. (a) Expense Lead - Operations and Maintenance Expense Mr. Joyce separated O&M expenses into two groups - energy costs and "other O&M" expenses. Each of those two groups was further divided into subgroups. 87 ~ Energy Costs Fuel. Mr. Joyce explains that, during the Test Year, ETI purchased two kinds of fuel: (1) coal and oil; and (2) natural gas. He concluded that there were 44.27 expense lead days for coal and oil, based upon the time between the service periods and payment dates or payment due dates for all coal and oil invoices from the Test Year. As to natural gas, he determined that there were 40.63 expense lead days, based upon a comparison of the service period and payment due dates and the payment dates from a random sample of gas invoices. 88 No party challenged this approach, and the AI..Js find no reason to do so either. Purchased Power. Mr. Joyce explained that there were two components to ETI's purchased power energy costs in the Test Year: (1) MSS-4 Purchases; and (2) Other Purchased Power (consisting of Joint Account Purchases, MSS-3 Purchases, Reserve Equalization, Cogeneration Purchases, Renewable Energy Credits, and Toledo Bend Purchases). Relying upon either the entire population or a sample from the Test Year (depending upon the category), Mr. Joyce concluded that there were 58.76 expense lead days for MSS-4, and 35.79 expense lead days for Other Purchased Power. 89 87 ETI Ex. 17 (Joyce Direct) at 11. 88 Id. at 11 and JJJ-3. 89 ETI Ex. 17 (Joyce Direct) at 12 and JJJ-3. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE40 PUC DOCKET NO. 39896 No party challenged the 35.79 day estimate for Other Purchased Power. However, on behalf of the Cities, Mr. Pous testified that the expense lead days for MSS-4 should be lengthened from 58.76 days to 60.65 days. According to Mr. Pous, Mr. Joyce made several errors in calculating the expense lead days for MSS-4 expenses. First, Mr. Joyce inadvertently placed the service period month after the billing month for two MSS-4 invoices. Mr. Pous based this conclusion on the fact that the expense leads for these two invoices are roughly 30 days shorter than the "vast majority" of the other invoices. 90 In response, Mr. Joyce denied that he erroneously placed the service period month after the billing month, and pointed out that Mr. Pous lacks any evidence to support his assertion. Instead, Mr. Joyce considered the entire population of MSS-4 invoices for the Test Year. Those invoices show payment lead days ranging from 30 to 120 days, with most points being near 30, 60, or 70 payment lead days. According to Mr. Joyce, this is reasonable and well within the range he has experienced in other rate cases. 91 Mr. Pous testified that Mr. Joyce erred in calculating the expense lead days for MSS-4 expenses by considering only the payment due dates specified in the Entergy System Agreement, rather than also considering the actual payment dates. According to Mr. Pous, in four instances during the Test Year, extensions were granted to ETI to allow it to make MSS-4 payments afterthe deadline specified in the Entergy System Agreement. Therefore, Mr. Pous stated that the expense lead days for MSS-4 payments should have been calculated using the later of the actual payment date or the allowable payment period.92 Mr. Joyce largely agreed with Mr. Pous on this point. That is, he agreed that the payment lead days should be based on the later of the paid date or the due date. However, he disagreed with some of Mr. Pous' calculations on this issue because Mr. Pous wrongly designated several due dates of Saturday or Sunday, when he should have selected Fridays as the due date. 93 90 Cities Ex. 5 (Pous Direct) at 83-84. 91 ETI Ex. 54 (Joyce Rebuttal) at 26-28. 92 Cities Ex. 5 (Pous Direct) at 84. 93 ETI Ex. 54 (Joyce Rebuttal) at 28-29. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE41 PUC DOCKET NO. 39896 Next, Mr. Pous testified that Mr. Joyce erred in calculating the expense lead days for MSS-4 expenses by erroneously concluding that one invoice had been paid on the first of the month when, in fact, it had been paid on the 18th of the month. 94 Mr. Joyce agreed with the change. 95 Mr. Joyce then recalculated the expense lead days for MSS-4 and revised the number of lead days from 58.76 to 59.81. 96 The AU s conclude that ETI has met its burden as to show that there were 59.81 expense lead days for MSS-4, and 35.79 expense lead days for Other Purchased Power. » Other O&M Expenses This category of expenses was broken down in the lead-lag study into four groups regular payroll costs, incentive payroll costs, affiliate service company costs, and all other O&M costs (such as materials, services, and so on). Regular Payroll Costs. The lead days for regular payroll costs were computed by determining the average days of service being reimbursed and adding the days between the end of each service period and the payments to employees. This amount was then adjusted to incorporate the effects of vacation pay based upon actual ETI data. By this method, Mr. Joyce determined the expense lead for regular payroll costs to be 20.68 days. 97 No party challenged this approach, and the ALls agree. Incentive Pay Costs. ETI has an annual employee incentive program in place. Incentive payments for the year 2010 were made in the first quarter of 2011. The lead days for incentive pay costs were based on the weighted days between the midpoint of the service period (i.e., July 1, 2010) and the date the incentives were paid (March 10, 2011). By this method, Mr. Joyce determined the 94 Cities Ex. 5 (Pous Direct) at 84. 95 ETI Ex. 54 (Joyce Rebuttal) at 29. 96 ETI Ex. 54 (Joyce Rebuttal) at JJJ-R-2. 97 ETI Ex. 17 (Joyce Direct) at 13 and JJJ-3. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE42 PUC DOCKET NO. 39896 expense lead for incentive pay costs to be 251.77 days. 98 No party challenged this approach, and the ALl s agree. Affiliate Service Company Costs and Other O&M. Costs. Charges from Entergy Services, Inc. (ESI) are paid in the month following the month in which the charges were incurred. The lead days for affiliate service company costs were based on the number of days from the mid-month to the later of the contractual due date or the actual settlement date in the following month. By this method, Mr. Joyce determined the expense lead for affiliate service company costs to be 39.64 days. 99 The lead days for other O&M costs were based on a random sampling from the Test Year. Mr. Joyce originally determined the expense lead for other O&M costs to be 47.46 days. 100 However, to correct an error on his part, Mr. Joyce subsequently revised the expense lead time for other O&M costs down to 43.89 days. 101 Mr. Po us testified that ETI' s "FAS 106-related expenses" were wrongly included in either the affiliate service company costs or the other O&M costs. FASB is the body that establishes the rules that constitute GAAP. FASB's Statement Number 106 (FAS 106) establishes the standards for an employer's treatment of the non-cash retirement benefits it gives its employees. Based on the action taken by the Commission in Docket No. 16705, 102 Mr. Pous believes that ETI's FAS 106 costs should have been separately identified and accounted for in the lead-lag study. He contended that, when those costs are properly accounted for, it results in an additional negative cash working capital of $3.8 million. 103 98 Id. at 14 and JJJ-3. 99 ETI Ex. 17 (Joyce Direct) at 15, and JJJ-3. 100 Id.at15-17,andJJJ-3. 101 ETI Ex. 54 (Joyce Rebuttal) at JJJ-R-2. 102 Application ofEntergy Gulf States, Inc.for Approval of Its Transition to Competition Plan and the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705, (Oct. 13, 1998). 103 Cities Ex. 5 (Pous Direct) at 85-88. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE43 PUC DOCKET NO. 39896 Mr. Joyce contended that the prior Commission decision upon which Mr. Pous relies, Docket No. 16705, dates from 1996, is inapplicable to the facts in the present case, is outdated, and has been superseded by subsequent Commission decisions. Mr. Pous advocated a 312.55-day expense lead for FAS 106 expenses. However, Mr. Joyce pointed out that, during the Test Year, ETI made its FAS 106 payments to a trust at the end of each month, resulting in a one-half month payment lead (15.25 days). Mr. Joyce testified that his treatment of FAS 106 expenses in his lead-lag study is consistent with the approach that was approved by the Commission in a recent Oncor ratemaking case, Docket No. 35717 . 104 The AIJs conclude that ETI met its burden to show that there were 39.64 expense lead days for Affiliate Service Company Costs and 43.89 expense lead days for Other O&M Costs. (b) Expense Lead- Current Federal Income Tax Expense As required by P.U.C. SUBST. R. 25.23l(c)(2)(B)(iii)(IV)(-f-), Mr. Joyce calculated the lead days for federal income taxes by measuring the days between the midpoints of the annual calendar year service periods and the actual dates on which ETI made its estimated quarterly tax payments. By this method, Mr. Joyce determined the expense lead for current federal income tax costs to be 38 days. He then determined that this resulted in a $1.6 million cash working capital requirement associated with the Company's Federal Income Tax Expenses. 105 Mr. Pous testified that the Company's cash working capital requirement for Federal Income Tax Expenses ought to be a negative number or, at most, zero. He bases this argument on his assertion that, during the past five years, the Company "has received in excess of a net $90 million of refunds" on its federal income taxes. In other words, because "refunds produce cash" for the 104 ETI Ex. 54 (Joyce Rebuttal) at 29-32. 105 ETIEx.17(JoyceDirect)at17,andJJJ-3. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE44 PUC DOCKET NO. 39896 Company, Mr. Pous contends that the Company is seeking a positive cash working capital 106 requirement for cash transactions "that have not been made and are not being made." Mr. Joyce responds by disputing Mr. Pous' contention that "refunds produce cash." Mr. Joyce points out that any refund from the IRS merely represents a return of the Company's own cash for payments previously made. Moreover, Mr. Joyce stresses that his approach for calculating the expense lead for current federal income taxes is perfectly consistent with: ( 1) the requirements of P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-f-); (2) current IRS guidelines found at IRS Publication 542; and (3) Commission precedent. Mr. Joyce further points out that, by contrast, Mr. Pous' approach has been consistently rejected by the RRC. 107 The Al.Js find Mr. Joyce's arguments to be more persuasive on this point and conclude that ETI has met its burden as to show that the expense lead for current federal income tax costs it utilized in the lead-lag study is reasonable and appropriate. The AlJ s conclude that ETI met its burden to show that there were 39 .64 expense lead days for Affiliate Service Company Costs and 43.89 expense lead days for Other O&M Costs. (c) Expense Lead and Lag-Taxes Other than Income Taxes This group of taxes consists of: (1) payroll-related taxes; (2) ad valorem taxes; (3) Texas state gross receipts taxes; (4) the PUC assessment tax; and (5) Texas state franchise taxes. Calculating from the midpoints of the work periods to the respective payment dates of the taxes, Mr. Joyce determined that the payroll taxes had an expense lead time of 16.45 days. As to the franchise taxes, Mr. Joyce concluded that the Company had a collection lag of 46.42 days because the Company was required to pay the taxes in May 2010. As to the other non-payroll-related taxes, Mr. Joyce calculated from the midpoint of the period for which the tax was assessed to the payment date, resulting in the following expense lead days: 213.51 days for ad valorem taxes; 74.28 days for Texas 106 Cities Ex. 5 (Pous Direct) at 88-89. 7 !0 ETI Ex. 54 (Joyce Rebuttal) at 33-36, JJJ-R-1. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE45 PUC DOCKET NO. 39896 state gross receipts taxes; and 225.50 days for the PUC tax. 108 No party challenged this approach, and the AU s agree. F. Self-Insurance Storm Reserve [Germane to Preliminary Order Issue No. S] In Docket Nos. 16705 and 37744, the Commission authorized ETI to maintain a reasonable and necessary storm damage reserve account of $15,572,000. 109 As of June 30, 1996, ETI had a positive reserve balance of $12,074,581, constituting a reduction to rate base. Over the next 15 years, ETI charged $101,670,803 to the reserve related to more thart 200 storms (excluding securitized events), but it accrued only $29,796,478 through base rates. Thus, ETI's end-of-test-year balance for its storm damage reserve in the present case was a negative $59,799,744. 110 This negative balance is an addition to rate base. 111 OPC and Cities argue that ETI's current storm damage reserve negative balance should be adjusted. OPC contends that ETI failed to prove that its storm damage expenses booked since 1996 were reasonable and prudently incurred, so it recommends disallowing all of those charges arid refunding to customers the resulting positive balance that exceeds the authorized balance. Alternatively, OPC suggests that ETI's negative balartce be reset to its currently authorized balance, with no refund to customers. Cities contend that ETI's current negative storm damage reserve balance should be reduced because it includes: unreasonable expenditures associated with a 1997 ice storm; expenses associated with former assets in Louisiarta; and amounts that Cities claim should have been treated as insurance deductibles. Cities also recommend transferring ETI' s Hurricane Rita Regulatory Asset to the storm damage reserve. The parties' recommendations are summarized as follows: 108 ETI Ex. 17 (Joyce Direct) at 18-19, and JJJ-3. 109 Staff Ex. 4 (Roelse Direct) at 8. l!O $12,074,581 + $29,796,478-$101,670,803 = ($59,799,744). 111 P.U.C. SUBST. R. 25.23 l(c)(2)(E). SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE46 PUC DOCKET NO. 39896 Party Reserve Balance ETI ($59 ,800,000) Cities ($34,051,597) OPC-1 $41,871,059 OPC-2 $15,572,000 1. The Effect of Prior Settled Cases As with the Hurricane Rita Regulatory Asset (Section V.B.), the effect of the black-box settlements in Docket Nos. 34800 and 37744 is a significant issue concerning the storm damage reserve. However, the parties' positions are generally reversed from the positions taken on the Hurricane Rita Regulatory Asset. That is, ETI now argues that its storm reserve negative balance was resolved and approved in those settled dockets, while Cities and OPC argue that it was not. ETI notes that the final orders in Docket Nos. 34800 and 37744 contained "stipulated and agreed upon" conclusions of law stating that overall total invested capital through the end of the test year in those cases met the requirements of PURA § 36.053( a) that electric utility rates be based on the original cost, less depreciation, of property used by and useful to the utility in providing service. 112 Then ETI cites language in P.U.C. SUBST. R. 25.231(c)(2)(E), which provides that any deficit in a self-insurance plan will be considered an increase to rate base, or invested capital. As a result, ETI argues, the Commission could not make a determination that a rate base expense item was included in rate base as used and useful without also determining that the rate base expense was prudently and reasonably incurred. 113 Thus, ETI asserts, a Commission conclusion of law that approved invested capital as meeting the requirements of PURA § 36.053(a) necessarily also determined that an expense included in rate base was prudently and reasonably incurred. In other 112 PURA§ 36.053(a) provides: "Electric utility rates shall be based on the original cost, less depreciation, of property used by and useful to the utility in providing service." 113 ETI cited: City ofAlvin v. Public Util. Comm'n of Texas, 876 S.W.2d 346, 353-354 (Tex. App.-Austin, 1993, no pet.); see also Application of Gulf States Utilities Company for Authority to Change Rates, Docket Nos. 7195 and 6755, 14 P.U.C. BULL. 1943 at 1969 (May 16, 1998) ("dishonest or obviously wasteful or imprudent expenditures constitutionally can be excluded from a utility's rate base. Such costs clearly are not used and useful in providing serviced to the public."). SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE47 PUC DOCKET NO. 39896 words, ETI states, the "prudent and reasonable" standard is incorporated into the "used and useful" standard in PURA § 36.053(a). ll 4 Therefore, ETI argues that by issuing a final orders in Docket Nos. 34800 and 37744 with conclusions of law that ETI's overall total invested capital met the requirements of PURA § 36.053( a), the Commission implicitly approved the negative balances of its insurance reserve in both prior dockets; consequently, those orders preclude litigation in the present 115 case of whether those expenses were prudently and reasonably incurred. Cities reject ETI' s contention that the storm damage reserve balance was approved in Docket Nos. 34800 and 37744. Cities point out that in order to comply with PURA, all final orders in rate cases must include a conclusion of law stating that the overall total invested capital through the end of the test year meets the requirements of PURA§ 36.053( a). However, Cities contend, pursuant to the parties' agreements in Docket Nos. 37744 and 34800, no determination was made as to what was included in ETI' s total invested capital in those cases. Cities explain that in Docket Nos. 37744 and 34800 Cities claimed that certain expenses were not properly included in the storm reserve balance, while ETI argues that they were. However, neither Cities nor ETI's recommendation was specifically approved as part of the base rate settlement and neither of their recommended balances may be considered as the basis for setting rates in those dockets. 116 Thus, Cities argues, in such "black box" settlements no specific storm reserve balance is approved unless expressly stated. Cities also argues that the final orders in Docket Nos. 37744 and 34800 could just as logically be interpreted as denying ETI' s request to include objectionable expenses in the storm damage reserve, because both orders specified that the revenue requirement approved in those cases did not include any prohibited expenses. Finally, Cities states that adoption of ETI' s arguments would make black- box settlements impossible in the future. 117 114 ETI cited Docket No. 7195, 14 P.U.C. BULL. at 1969 ("the prudent investment test is embodied in traditional ratemaking principles as expressed through PURA Sections ... 41."). PURA Section 4l(a) is the predecessor to current Section 36.053. 115 ETI Initial Brief at 20-22; ETI Reply Brief at 17. 116 Docket No. 37744, Final Order at Ordering Paragraph 14; Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 at Ordering Paragraph 12. 117 Cities Reply Brief at 22-26. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE48 PUC DOCKET NO. 39896 OPC makes arguments similar to Cities, and notes that no storm damage reserve amount was either agreed to by the parties or approved by the orders in either Docket No. 34800 or Docket No. 37744. 118 The ALls find that the Commission did not implicitly approved all of ETI's storm damage expenses and its storm damage reserve balances in the final orders in Docket Nos. 34800 and 37744. Although the orders in those settled cases contained conclusions of law the that overall total invested capital through the end of the test year met the requirements of PURA § 36.053(a), the orders made no findings of what the total invested capital included, and specifically there were no findings or conclusions approving the amount of the storm damage reserve. As pointed out by Cities, in those dockets the intervenors disputed various items in ETI' s requested storm damage reserve, but the "black box" settlement did not specifically address those issues; consequently, it is as logical to conclude that objectionable expenses were excluded from the storm damage reserve and from the total invested capital as it is to conclude that the objectionable expenses were included. In Section V .B., the ALl s conclude that ETI' s Hurricane Rita regulatory asset should be considered as being inclu~ed in the black-box settlement and final order in Docket No. 37744, even though the settlement and order did not expressly state how the Hurricane Rita regulatory asset issue was resolved. However, that issue involved unique circumstances and is distinguishable because PURA § 39.459(c) required the Commission to consider the insurance payments for the Hurricane Rita restoration expenses in ETI' s next rate case, which was Docket No. 37744; ETI requested a true-up in that docket of the insurance proceeds it received concerning the regulatory asset; and no party objected to ETI' s proposed regulatory asset or its proposed amortization. In contrast, intervenors in Docket Nos. 34800 and 37744 did object to ETI' s proposed storm damage reserve and, under those circumstances, it is not possible to determine how the issues concerning the storm damage reserve were resolved by the black-box settlement. Therefore, the ALl s find that the black-box settlements and final orders in Docket Nos. 34800 and 37744 neither approved nor disapproved the reasonableness and necessity of ETI' s storm damage expenses incurred since 1996 or ETI' s current storm damage reserve negative balance. 118 OPC Reply Brief at 7-8. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE49 PUC DOCKET NO. 39896 2. OPC's Proposed Adjustment OPC witness Nathan Benedict testified that ETI failed to prove that any of its $101,670,803 in storm damage expense booked since 1996 was prudently incurred, so he recommended disallowing all of those charges and refunding to customers the resulting positive balance that exceeds the authorized balance. Removing those charges would leave ETI with a current positive storm reserve balance of $41,871,059 (beginning balance of $12,074,581 + accruals of $29,796,478). This balance exceeds the currently approved storm reserve balance of $15,572,000 by $26,299,059, and Mr. Benedict proposed that this surplus be refunded to rate payers at a rate of $1,314,953 per year for 20 years. Mr. Benedict acknowledged that some storm damage expenses incurred by ETI since 1996 likely were reasonable and necessary. Therefore, as an alternative proposal, Mr. Benedict suggested that ETI' s current storm balance reserve be set at the last approved amount of $15,572,000 (i.e., without any surplus or deficit). This proposal would result in a $75,363,744 reduction to ETI's current storm damage reserve negative balance and rate base. 119 As discussed above, OPC disagrees with ETI's argument that the Commission implicitly approved these expenses in the final orders in Docket Nos. 34800 and 37744. 120 Therefore, OPC argues that ETI had to prove in the present case that the expenses were prudently incurred. Concerning ETI's burden of proof, OPC acknowledges that, although a utility has the ultimate burden to prove that its proposed rates are just and reasonable, once the utility establishes a prima f acie case of prudence of a rate change, the burden shifts to the other parties to produce evidence to rebut that presumption. Then, if the other parties rebut the presumption, the burden shifts back to the utility to prove by a preponderance of the evidence that the challenged expenditures were prudent. However, OPC notes, if the utility fails to establish a prima facie case, the burden of going forward with evidence never shifts to the other parties. 121 In OPC's opinion, ETI never established a prima facie case because ETI' s spreadsheet of storm damage expenses was excluded from evidence and 119 OPC Ex. 6 (Benedict Direct) at 6-16; OPC Initial Brief at 19. 120 OPC Reply Brief at 7-8. 121 OPC Reply Brief at 2-3, citing, Entergy Gulf States, Inc. v. Public Utility Comm'n, 112 S.W.3d 208 (Tex. App. - 2003, pet. denied). SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE SO PUC DOCKET NO. 39896 ETI witness Greg Wilson acknowledged on cross examination that he made no analysis of whether ETI' s storm damage costs were reasonable and necessary. 122 ETI complains that Mr. Benedict simply sought a global rejection of more than $100 million of expenses without any evidence to support his position, and it stressed that even Mr. Benedict acknowledged that some of ETI' s expenses were prudently incurred. ETI also states that, in any event, it met its burden of proof with regard to expenses booked to the storm damage reserve. Concerning its proof, ETI states that its burden was to make a prima facie case supporting the prudence of its invested capital, 123 and once it made that showing, the burden shifted to the opposing parties to overcome the presumption of prudence by presenting evidence that reasonably challenged the expenditures. 124 This is the same position as OPC. ETI argues that it met its burden to prove a 125 primafacie case. ETI notes that it provided storm cost data accompanied by narrative testimony that supported the reasonableness of ETI's self-insurance plan; storm preparedness and response; service quality; and cost of labor, materials, and services used to carry out distribution activities (including system restoration). For instance, ETI states, it presented its proposed storm reserve balance through the direct testimony of Mr. Greg Wilson 126 and in the Commission's rate filing package. 127 Mr. Wilson also explained the function of ETI' s self-insurance program, described the $50,000 threshold to exclude minor weather events, and provided work papers detailing the nominal and trended losses for each storm booked to the reserve since 1986, as well as annual and total loss levels. 128 122 OPC Reply Brief at 1-5. 123 ETI Initial Brief at 22, citing, Application of Texas Utilities Electric Company for Authority to Change Rates, Docket No. 9300, 17 P.U.C. BULL. 2057, 2148, Order on Rehearing (Sept. 27, 1991). 124 Docket No. 9300, 17 P.U.C. BULL. at 2148. 125 Although ETI contended that the storm damage reserve has been approved in prior dockets, it argued that its evidence also supported storm damage charges going back to July l, 1996. ETI Initial Brief at 23, n. 147. 126 ETI Ex. 14 (Wilson Direct) at 11. 127 ETI Ex. 3 (Schedules) at Schedule B-1, line 7; Schedule WP_B-1, page 7. 128 ETI Ex. 14 (Wilson Direct) at 5-7; WP GSW-3_1. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 51 PUC DOCKET NO. 39896 Further, ETI witness Shawn Corkran presented testimony regarding subject matters that directly support the ability of the system to withstand storms, and ETI's ability to reasonably and efficiently respond to storm events, thereby supporting the conclusion that reasonable and necessary costs are booked to the storm reserve balance. This evidence included ETI' s distribution operations, industry-recognized comprehensive storm plans, annual storm drills, storm response and restoration processes, distribution maintenance and asset improvement processes, service quality and continuous improvement programs, and vegetation management practices. ETI points out that Mr. Corkran also described how it prepares for emergency situations, 129 and Mr. Corkran explained how charges to the storm reserve are captured and recorded. 130 Mr. Corkran also noted that ETI has received either the Edison Electric Institute' s Emergency Assistance Award or Emergency Response Award every year since 1998, which recognize ETI' s exemplary storm restoration response. 131 Likewise, Mr. Corkran discussed ETI' s reliability statistics since 2000, which demonstrated a high quality of service, 132 and he provided four exhibits demonstrating that, on both per-kilowatt-hour (kWh) and per-customer bases, ETI' s distribution O&M costs compared favorably to the costs of other utilities. 133 In ETI' s opinion, because it carried out its distribution activities in the same efficient and cost-effective manner while performing routine activities as during storm restoration, those metrics and reliability statistics support the reasonableness of costs booked to the reserve. 134 ETI also argues that it supported the reasonableness of the costs booked to its storm reserve through the direct testimony of its supply chain witness, Mr. Joseph Hunter. Mr. Hunter explained that ETI' s procurement policies and procedures are designed to streamline the acquisition of materials and services through the use of strategic supply networks in order to achieve the lowest 129 Id. at 28. 130 Id. at 93. 131 Id. at 29. 132 Id. at 12-29. 133 Id., Exhibits SBC-2A, SBC-2B, SBC-2C, and SBC-20. 134 ETI Initial Brief at 22-24. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE52 PUC DOCKET NO. 39896 reasonable cost. 135 Mr. Hunter also described how the centralization of the supply chain function on a system-wide basis provides greater leverage and buying power in the procurement of materials and, 136 thus, lower costs than could be achieved by ETI alone. Furthermore, Mr. Hunter specifically noted that the standardization of supply chain activities "makes possible a smoother day-to-day operation 137 as well as rapid response to major storms or emergencies." Finally, ETI stated that it provided an extensive amount of storm reserve data through the discovery process, which provided a basis for any interested party to investigate the reasonableness of any particular storm response or expenditure booked to the reserve. It stressed that OPC witness Benedict acknowledged that ETI provided 420 pages and over 22,220 lines of detail reflecting every charge to the storm reserve over the last 15years, 138 which specified the month, year, state, project code, work order type, function, storm name, account number, resource code, resource code description, and amount. 139 Therefore, ETI argues that it made a primafacie case regarding its storm reserve through the presentation of narrative testimony, schedules, work papers, and expense detail and, accordingly, the burden shifted to parties seeking to disallow the expenses allocated to the storm damage reserve to present evidence that reasonably challenges their prudence. 140 Yet, ETI contends, OPC did not challenge any specific expenditure booked to the reserve other than the 1997 ice storm expenses discussed later. Therefore, ETI argues that it met its prima facie burden and OPC's 141 proposed disallowance of either $101,670,803 or $75,363,744 should be denied. Although it is a close call, the ALls find thatETI established aprimafaciecasethat its storm damage expenses incurred since June 30, 1996, were prudently incurred. A prima facie case is a low burden. It is not the same as a preponderance of the evidence. Rather, as stated in Town of Fairveiw 135 ETI Ex. 16 (Hunter Direct) at 5, 9-10, and Exhibits JMH-l(Entergy Companies' Procurement Policy) and JMH-3 (Entergy Companies' Approval Authority Policy). 136 ETI Ex. 16 (Hunter Direct) at 17. 137 Id. at 18 (emphasis added). 138 Tr. at 1703. 139 Tr. at 1704. 140 Docket No. 9300, 17 P.U.C. BULL. at 2147. 141 ETI Initial Brief at 22-26; ETI Reply Brief at 16-19. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE53 PUC DOCKET NO. 39896 v. City ofMcKinney, prima facie evidence "is merely that which suffices for the proof of a particular fact until contradicted and overcome by other evidence." 142 Similarly, Black's Law Dictionary defines a prima facie case as sufficient evidence "to allow the fact-trier to infer the fact at issue and rule in the party's favor." 143 Except for expenses incurred with the 1997 ice storm, ETI did not present any testimony that explicitly stated that the expenses included in its storm damage reserve were prudently incurred. However, ETI did present sufficient other evidence that at least allows the ALJs to infer that the expenses were prudently incurred. As noted above, a reasonable inference from the evidence presented is sufficient to establish a prima facie case. ETI witness Gregory Wilson presented testimony about the background of the storm damage reserve and about ETI' s yearly major storm damage losses, although OPC is correct that he did not explicitly evaluate or determine whether ETI' s expenses were reasonable and necessary. 144 In addition, OPC witness Benedict provided testimony that ETI has booked $101,670,908 to the storm damage reserve since 1996, 145 and that ETI' s $50,000 threshold is a means of excluding from the reserve small storm-related expenses that ETI could anticipate as routine O&M expense and which should be excluded from the storm damage reserve. 146 ETI presented testimony that it had not recorded storm damage expense to both the storm damage reserve and to O&M expense, 147 and Mr. Benedict agreed that he had no information to 148 contradict this or that any securitized costs were charged to the storm damage reserve. 149 Although the document itself was excluded from evidence, Mr. Benedict testified that ETI provided him with a 420-page spreadsheet covering all of ETI's storm damage expenses back to 1996, including the month, year, state, project code, project name, work order type, function, storm name, 142 271 S.W.3d 461, 467 (Tex. App. Dallas 2008 pet. denied). 143 Black's Law Dictionary, 8th Ed. (2004). 144 ETI Ex. 14 (Wilson Direct) at Ex. GSW-3. 145 OPC Ex. 6 (Benedict Direct) at 7-8. 146 Tr. at 1694. 147 ETI Ex. 72 (Wilson Rebuttal) at 2-3. 148 Tr. at 1695-1696. 149 Tr. at 1698. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE54 PUC DOCKET NO. 39896 account number, resource code, resource code description, and amount. 150 In addition, ETI provided other testimony described previously concerning its distribution operations, storm plans, storm response operations, purchasing procedures, and the like. ETI did not present a witness who specifically testified that all of its storm damage expenses booked to the storm damage reserve were prudently incurred, except for expenses related to the 1997 ice storm. Such testimony would have been more helpful than the evidence ETI relied upon. Nevertheless, the burden of establishing a primafacie case does not require such direct testimony, if a fact can be reasonably inferred from other evidence presented. The AU s reiterate that it is a close call, but they find that ETI did present sufficient evidence to infer that the expenses charged to the storm damage reserve were prudently incurred. At that point, the burden shifted to OPC to produce evidence to challenge specific expense items included in the storm damage reserve, but OPC did not present any such evidence except for the items discussed below. Therefore, the AUs recommend that the Commission not adopt either of 0 PC's recommended denials of expenses contained in ETI' s storm damage reserve. 3. 1997 Ice Storm ETI's proposed negative storm reserve balance includes $13,014,379 in expenditures associated with a 1997 ice storm. Cities and OPC contend that this expense should be excluded from the storm balance reserve. Cities witness Pous explained that ETI first requested to include the 1997 ice storm expense in the storm damage reserve as a post test year adjustment in its 1995-1996 test-year rate case, Docket No. 16705. The Commission denied the requested post test year adjustment and stated that the expense should be considered in ETI's next rate case. Thereafter, ETI had a series of rate cases (Docket No. 20150 1998 rate case; Docket No. 30123 -2004 rate case; Docket No. 34800-2007 rate case; Docket No. 37744-2009 rate case) in which intervenors challenged the 1997 ice storm expenses, but those cases all settled or were otherwise concluded without any express decision 150 Tr. at 1704. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE55 PUC DOCKET NO. 39896 concerning the prudence of ETI' s 1997 ice storm expenses. 151 Mr. Po us testified that these expenses are now appropriately at issue in the present case, and he recommended that the entire balance be excluded from the storm damage reserve. He pointed out that in Docket No. 18249, the Commission found that ETI' s poor quality of service exacerbated the extent of damage caused by the storm, and it found that the response efforts were uneven and delayed and could have been more effective if ETI had a better communication and management program in place. 152 Mr. Pous also contended that in the present case ETI failed to prove that any portion of the 1997 Ice Storm expenses were reasonable. 153 Thus, Cities argue that the Commission has already determined that ETI' s negligence was a major factor in the extent and duration of the outages, 154 so no expenses associated with the 1997 ice storm should be eligible for recovery from customers through the storm damage reserve. In response to ETI's argument that it was already penalized for these issues in Docket No. 18249 through a reduction to the allowed ROE, Cities argue that the Commission did not absolve ETI from responsibility for damage caused by ETI's poor service quality, and ETI's customers should not be ordered to pay for expenses that were caused by ETI's negligence. 155 OPC makes the same arguments as Cities concerning the 1997 ice storm expenses. 156 ETI argues that, due to quality of service issues related to the 1997 ice storm, the Commission reduced Entergy Gulf States, Inc.' s (EGSI) ROE by 60 basis points in Docket No. 18249 and subjected EGSI to significant spending requirements and quantified performance guarantees. In ETI's opinion, it would be inequitable to now penalize ETI a second time for the 151 Cities Ex. 5 (Pous Direct) at 49-55. 152 Entergy Gulf States, Inc. Service Quality Issues Severed From Docket No. 16705, Docket No. 18249, Final Order at FoF 97, 98, & 102 (Apr. 21, 1998). 153 Cities Ex. 5 (Pous Direct) at 56-59; see Cities Initial Brief at 18-19. 154 Cities Initial Brief at 18 ("The Company's failure to clear the limbs before the storm was a major factor in the number and duration of outages experienced by customers."). 155 Cities Reply Brief at 28-30. 156 OPC Ex. 6 (Benedict Direct) at 12; OPC Initial Brief at 16; OPC Reply Brief at 7-10. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE56 PUC DOCKET NO. 39896 same issues. Moreover, ETI argues that it established that its expenses were reasonable and necessary. ETI witness Shawn Corkran testified that the 1997 ice storm was the most destructive winter storm ever to hit the EGSI/ETI system, with about 3,400 miles of distribution lines and 560 miles of transmission lines de-energized during the storm's peak. A large part of the restoration effort involved clearing broken and fallen trees and tree limbs from lines. Mr. Corkran reviewed all of the costs incurred in response to the 1997 ice storm and stated that they were reasonable and necessary to reliably restore service to customers as quickly as possible after the storm. He provided an exhibit with a detailed breakdown of labor, materials, transportation, lodging, and other expenses incurred. In his opinion, all of these costs charged to the storm damage reserve, totaling $13,014,379, were reasonable, necessary, and prudently incurred. 157 The ALls recommend that the Commission authorize ETI to include in the storm damage reserve its $13,014,379 in expenditures associated with the 1997 ice storm. ETI established that those expenses were reasonable and necessary to repair the damage and restore power to its customers. ETI witness Mr. Corkran provided detailed testimony concerning the seriousness of the storm and the resulting expenses incurred for repair work and restoration of power to customers. 158 In contrast, Cities and OPC did not challenge any specific item in these restoration expenses. Instead, they relied upon the Commission's findings in Docket No. 18249 that ETl's deficient maintenance exacerbated the amount of damage caused by the storm. However, in that docket the Commission also reduced ETI' s ROE by 60 basis points due to poor service issues, including deficient preventative maintenance. The Commission made the reduction in ROE retroactive and required ETI to make refunds to customers. Likewise, in that docket the Commission found that the ice storm was severe and that significant damage would have occurred even with exemplary vegetation management and other preventative measures. It is not feasible to accurately determine now what portion of ice storm damage that occurred 15 years ago was caused by preventative maintenance issues. 157 ETI Ex. 48 (Corkran Rebuttal) at 2-12. 158 ETI Ex. 48 (Corkran Rebuttal) at 2-12 and Ex. SBC-R-1. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE57 PUC DOCKET NO. 39896 The Al.Js conclude, however, that the Commission's retroactive reduction ofETI's ROE in Docket No. 18249 in part compensated ratepayers for the poor service issues that exacerbated the storm damage. Nevertheless, once the ice storm occurred, ETI had to take appropriate action to repair the damage and restore service. ETI has established the expenses incurred in those efforts were reasonable and necessary, and the Al.Js find that they should be included in the storm damage reserve. Therefore, the AUs recommend that the Commission deny Cities and OPC's proposed adjustment. 4. Jurisdictional Separation Plan Allocation Cities complained that ETI's storm damage reserve deficit includes $12,498,325 in costs that belong to Louisiana jurisdiction customers but were incorrectly transferred to Texas customers during implementation of the Jurisdiction Separation Plan. Cities explain that before the jurisdictional separation of EGSI into ETI and Entergy Gulf States Louisiana, LLC (EGSL), the transmission investment and expense associated with maintaining the transmission system, including storm restoration costs, was allocated between the Texas and Louisiana retail jurisdictions. In the jurisdictional separation of EGSI into ETI and EGSL, the transmission system investment was split between each company based upon a situs basis. The transmission facilities in Texas were transferred to ETI and the transmission facilities in Louisiana were transferred to EGSL. After the jurisdictional separation, ETI and EGSL were each responsible for future O&M expense, including storm restoration expense, associated with their respective transmission investments. Cities claim that in the present case ETI has attempted to reverse the allocation of expenses incurred on behalf of Louisiana customers before the jurisdictional separation and to charge those expenses to Texas customers through the storm damage reserve. In Cities' opinion, any expense that was allocated to Louisiana customers prior to the jurisdictional separation was properly charged to Louisiana customers. Cities argue that ETI may not now reverse expenses allocated to Louisiana SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE58 PUC DOCKET NO. 39896 customers and charge them to Texas customers solely on the basis that ETI acquired the transmission investment located in Texas. 159 In response, ETI witness Considine explained that an analysis of storm reserve charges was preformed prior to the jurisdictional separation to determine if storm charges were incurred for Texas or Louisiana property. The reclassification of certain charges was made as a result of that analysis, which is in evidence, to properly reflect the state in which the storm charges were incurred. The largest charge assigned to ETI through this analysis was a $10,652.130 charge related to project "E2PPSJ8291 Trans EGSI-TX Hurricane Rita 9-24-05," which expressly related to damages to the Texas portion of the former EGSI transmission system. Similarly, costs were assigned from ETI to EGSL for projects such as "E2PPSJ8296 Trans. Hurricane Katrina - EGSl-La" and "E2PPSJ8302 Trans EGSI-LA Hurricane Rita 9-24-05," that clearly related to assets located in Louisiana. In other words, prior to the separation, the Texas portion of the storm damage reserve could include charges for restoration work performed on assets located in Louisiana, and vice versa. The analysis conducted pursuant to the separation re-aligned the charges to the jurisdiction where the assets are located. In that way, ETI argues, neither jurisdiction has charges in its storm reserve balance for assets located in the other jurisdiction. In short, ETI argues that the assets and liabilities following the separation have been properly assigned and no improper cost shifting occurred. 160 The ALJ s recommend that the Commission deny Cities' proposed adjustment. ETI offered evidence to explain how its reclassification study reassigned various costs from the Texas jurisdiction to Louisiana, as well as from the Louisiana jurisdiction to Texas. This study resulted in more expenses from Louisiana being reassigned to the Texas jurisdiction than from Texas to Louisiana, but Cities offered no evidence to explain why the study was flawed or why the reassignments were in error. The ALJs found ETI's evidence to be credible and that it supported the jurisdictional allocation of these expenses as proposed by ETI. 159 Cities Ex. 5 (Pous Direct) at 59-60; Cities Initial Brief at 19-20. 160 ETI Ex. 46 (Considine Rebuttal) at 25 and Ex. MPC-R-3 at 25; ETI Initial Brief at 19-36; ETI Reply Brief at 20-21. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE59 PUC DOCKET NO. 39896 5. $50,000 Reserve Threshold Cities witness Pous also proposed a $10,950,000 reduction to ETI' s negative storm damage reserve balance due to ETI including in the reserve the first $50,000 of expense for each separate storm event. Mr. Pous asserted that this amount is equivalent to a deductible for insurance purposes and should have not been charged to the reserve. Cities note that P. U. C. SUBST. R. 25 .231 (b)( 1)(G) requires that a storm reserve only collect for "property and liability losses which occur, and which could not have been reasonably anticipated and included in operating and maintenance expenses." Because of ETI's low $50,000 threshold, Cities contend, ETI has recorded to. the storm reserve expenses associated with 219 different weather events in the past 15 years. This equates to approximately 14.6 weather events per year, or 1.2 weather events per month, on average. In Cities' view, ETI' s booking to the storm damage reserve of all expenses associated with a weather event exceeding $50,000 - including the first $50,000 - is inconsistent with P.U.C. SUBST. R. 25.23l(b)(l)(G). Cities argue that ETI may not reasonably claim that such a recurring expense is "not reasonably anticipated" to qualify it for the storm reserve. Cities proposed adjustment is based on $50,000 for each of the 219 storm events, for a total of $10,950,000. In addition, based on the nature of ETI's recurring storm expense, Cities also recommend that the deductible amount be increased to $500,000, which Cities stated is consistent with the storm reserve treatment afforded to other utilities in Texas. 161 ETI witness Gregory Wilson testified that Mr. Pous misconstrued the $50,000 trigger when he treated it as a deductible. Mr. Wilson explained that if a storm causes $50,000 or less in damage, the expenses are not charged to the storm damage reserve. However, if a storm causes more than $50,000 in damage, all of the expenses are charged to the reserve. He noted that if the $50,000 were treated as a deductible, then that amount would still be charged to O&M whenever storm damage exceeded the $50,000 threshold. But, under the current arrangement, when storm damage exceeds $50,000 all of the expenses are charged to the storm damage reserve, and the first $50,000 is not charged to O&M. Therefore, no double recovery occurs. Moreover, ETI argues that Cities' proposed retroactive removal of these amounts from the reserve would constitute a disallowance of 161 Cities Ex. 5 (Pous Direct) at 61-63; Cities Initial Brief at 20-21. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE60 PUC DOCKET NO. 39896 costs without any finding of imprudence, as well as impermissible retroactive ratemaking. ETI also contends that even if the Commission were to implement Mr. Pous' s recommendation prospectively, it would require a corresponding increase in ETI' s O&M costs. Therefore, ETI disagreed with Cities' recommendation to reduce the current balance of the storm damage reserve by $10,950,000 or to change the current level of the threshold. 162 The AlJs find that Cities' proposed adjustment to ETI's storm damage reserve is not warranted. ETI explained that the $50,000 threshold amount was included in the storm damage reserve whenever storm restoration expenses exceeded the threshold, but that amount was not included in O&M expense. Accordingly, no double recovery has occurred, and Cities presented no other valid reason to disallow the allocation of these expenses to the storm damage reserve. Therefore, the A1J s recommend that the Commission deny Cities' proposed $10,950,000 adjustment to ETI's current storm damage reserve balance. As a policy matter, the Commission may choose to increase ETI' s threshold on a prospective basis to some higher amount, as recommended by Cities, but the evidence presented by the Cities on this issue was not sufficient for the A1J s to make such a recommendation. 6. Hurricane Rita Regulatory Asset As discussed in Section V.B., Cities recommend an adjustment to the Hurricane Rita regulatory asset, and they recommended the adjusted balance be moved to the storm damage reserve. For the reasons stated in Section V .B., the AlJs recommend that the Commission not adopt Cities' proposal to move the Hurricane Rita regulatory asset to the storm damage reserve. 7. Conclusion In conclusion, the AlJs find that ETI's storm damage expenses since 1996 and its storm damage reserve balance were not approved by the Commission as a result of the black-box settlements in Docket Nos. 34800 and 37744. The AlJs also find that ETI established aprimafacie case concerning the prudence of its storm damage expenses incurred since 1996 and that intervenors' 162 ETI Ex. 72 (Wilson Rebuttal) at 2-3; BIT' s Initial Brief at 27-28; ETI Reply Brief at 21-22. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE61 PUC DOCKET NO. 39896 proposed adjustments should be denied. Therefore, the ALJ s recommend that the Commission approve ETI's test-year-end storm reserve balance of negative $59,799,744. G. Coal Inventory ETI is the partial owner of two coal-fired power generating facilities. It owns a 29. 75 percent interest in Nelson 6, a 550 megawatt (MW) unit located in Westlake, Louisiana (Nelson), and a 17 .85 percent interest in Big Cajun II, Unit 3, a 588 MW unit located in New Roads, Louisiana (BCIUU3). EGSL is the majority owner and operator of Nelson and is responsible for the supply and delivery of coal to that facility. A third party, LaGen, is a co-owner of BCIUU3, and is the operator of the plant. Pursuant to a joint operating agreement between the co-owners, LaGen is responsible for the acquisition and delivery of coal to BCIUU3. The coal for both units comes, via train, from minefields in Wyoming. 163 Entergy has adopted a "Coal Inventory Policy" at Nelson to ensure that a sufficient coal inventory is always maintained on-site to help mitigate transportation and unit operating risks. The policy calls for, among other things, a 12-month average inventory target of a 43-day supply of coal. Because Entergy is not the operator of BCIUU3, it does not have ultimate control over the coal inventories at that unit. Pursuant to the joint operating agreement for that unit, however, each year ETI nominates for the next calendar year the level of coal to be delivered for its account at BCIUU3. ETI' s nomination process is targeted to ensure an end-of-year inventory target of a 43-day supply of 164 coal. In its application, ETI includes a coal inventory amount in its rate base that is based upon the average inventories at Nelson and BCIUU3 for the 13 months ending in June 2011. 165 The average coal inventory at Nelson was 384,860 tons, representing approximately 48 days of inventory, 163 ETI Ex. 33 (Trushenski Direct) at 3-4. 164 ETI Ex. 33 (Trushenski Direct) at 30-31. 165 ETI Ex. 68 (Trushenski Rebuttal) at 2. Notably, the amount ETI is seeking in its Rate Base is calculated upon a 13-month average ending June 2011 (the last month of the Test Year), even though that amount is slightly less than the 12-month average for the Test Year. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE62 PUC DOCKET NO. 39896 assuming an average daily burn rate of 8,000 tons. The total proposed dollar amount for the coal inventories at both facilities is $9,846,037. Of that total, the Nelson portion is $6,040,926, and the BCIUU3 portion is $3,805,111. 166 ETI witness Ryan Trushenski, the Manager of the Solid Fuel Supply Group for ESI, testified that the coal inventory levels that were maintained at Nelson and BCII/U3 during the test year were reasonable and the costs 'incurred to maintain those levels were reasonable. 167 Cities do not challenge the reasonableness of the Company's 43-day inventory targets. Rather, Cities point out that the size of the actual inventory that was maintained on-site at Nelson during the Test Year exceeded the Company's inventory target level. Therefore, Cities contend that customers should not be forced to pay for inventory levels exceeding a 43-day supply (the amount that the Company determined, through its Coal Inventory Policy, to be a reasonable and necessary inventory to maintain on-site). According to Cities' witness, Karl Nalepa, a 43-day inventory of coal at Nelson would equate to 340,000 tons. He recommends that the value of a 43-day supply of coal be included in the rate base, but that $1,451.415 be excluded from the rate base to account for inventory at Nelson that was in excess of the 43-day supply. 168 The evidence shows that the Company's inventory "target" was a 43-day supply, while actual inventories during the Test Year averaged around a 48-day supply. Mr. Trushenski pointed out, and the A1J s concur, that the 43-day "target" was never intended to represent a hard and fast figure from which no deviations could be allowed. Rather, the target merely represents an operational planning tool. Moreover, there are many real-world factors - such as train cycle times, coal burn rates, and so on - that can cause the actual coal inventory to fluctuate over time. 169 The ALls conclude that the 48-day coal inventory was acceptably close to the 43-day target and was not unreasonable. The total proposed dollar amount for this coal inventory is $9,846,037. The ALls conclude that the full value of the coal inventory was reasonable and should be included in rate base. 166 ETI Ex. 68 (Trushenski Rebuttal) at 2, and 3 at WP/P RB 4.2. 167 ETI Ex. 33 (Trushenski Direct) at 30-31. 168 Cities Ex. 6 (Nalepa Direct) at 28-29, 6C and 6E. 169 ETI Ex. 68 (Trushenski Rebuttal) at 4. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE63 PUC DOCKET NO. 39896 H. Spindletop Gas Storage Facility ETI relies upon a variety of fuel types to generate electricity. A major fuel component is natural gas. However, energy generated from natural gas typically has the highest marginal cost and, therefore, it is most often the last resource deployed to generate electricity. The fluctuation of natural gas demand resulting from the changes in instantaneous demand is known as "swing." Although a portion of the system's base load requirement is met with natural gas, the primary role of natural gas 170 is as a swing fuel on the system. Since 2004, ETI has owned and used the Spindletop Facility. ETI, through a third-party operator, uses the Spindletop Facility to maintain a natural gas inventory that can be used to supply ETI's Sabine Station and Lewis Creek power generating facilities. Spindletop consists of two 171 salt-dome storage caverns (and associated equipment) located near Sabine Station. The Spindletop Facility serves a function similar to that of a city water tower - it enables ETI to buy natural gas at one point in time, store it, and use it at some future point when supplies are not available elsewhere or when peak needs cannot otherwise be met. ETI maintains that the primary benefit of the Spindletop Facility is that it provides: (1) supply reliability; and (2) swing flexibility. "Supply reliability" means that the facility can provide a reliable supply of gas for Sabine Station and Lewis Creek during potential gas supply curtailments, such as can occur during hurricanes, freezes, or other unusual events. In a worst-case scenario, the Spindletop Facility is capable of providing 100 percent of the fuel requirements for all five units at Sabine Station and one Lewis Creek unit for four days at 70 percent of capacity. The Spindletop Facility also allows the Company to avoid almost all intra-day gas purchases for Sabine Station. This is important because intra-day purchases tend to be more expensive than longer-term purchases. 172 Because major supply disruptions are more likely to occur during hurricane season and during the winter, ETI manages its gas inventories conservatively during the period from June 170 ETI Ex. 28 (Mcllvoy Direct) at 7. 171 Id. at 31. 172 ETI Ex. 28 (Mcllvoy Direct) at 32-33; ETI Initial Brief at 39, n. 264. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE64 PUC DOCKET NO. 39896 through March in order to ensure that it can provide a reliable supply of fuel to meet peak generation loads for four consecutive days. During the remainder of the year, ETI will consider withdrawing gas from the Spindletop Facility when the current day spot market price is higher than the replacement cost for the gas, as determined by future market indicators. Conversely, ETI injects gas into the Spindletop Facility when the cost of gas in the current market is less than the price of gas in the futures market. 173 For these various reasons, ETI witness Karen Mcllvoy, who is employed as the manager of ESI' s Gas & Oil Supply Group, testified that that Spindletop Facility is used and useful for providing reliable, economical service to ETI' s customers. 174 ETI witness Devon Jaycox, who is employed as the manager of ES I's Operations and Planning Group, testified that the Company is always evaluating how much reliability the Spindletop Facility can provide as compared to other options. He explained that, at Sabine Station, there is no other option that can provide ETI with the same level of reliability and flexible swing service that the Spindletop Facility provides. 175 Cities are critical of the Spindletop Facility, contending that the costs of operating it outweigh the benefits gained from it. No other party challenged ETI' s use of the Spindletop Facility. Cities' witness Karl Nalepa testified that it costs ETI $13,219 ,097 per year to operate the gas storage facility, whereas the Company could achieve the same supply reliability and swing flexibility benefits it gets from the Spindletop Facility through other gas supply options at a cost of only $1,724,659, thereby saving its customers $11,494,438. Thus, Mr. Nalepa stated that it is imprudent for ETI to continue operating the Spindletop Facility. 176 Mr. Nalepa testified that no other Entergy operating company owns or leases its own gas storage facility, yet those other companies are able to satisfy their needs for supply reliability and swing flexibility through other methods, such as existing gas supply and transportation contracts, at much lower costs. According to Mr. Nalepa, those other companies obtain supply reliability and swing flexibility through the use of monthly, daily, and intra-day natural gas supply contracts. In 173 ETI Ex. 28 (Mcllvoy Direct) at 33-34. 174 Id. at 37. 175 Tr. at 966. 176 Cities Ex. 6 (Nalepa Direct) at 18-20; Cities Ex. 6B (Errata No. 2). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE65 PUC DOCKET NO. 39896 support of this claim, he pointed to one of the operating companies, EGSL, as an example. He pointed out that EGSL has no firm transportation contracts, no firm supply contracts, and no fuel oil back-up at its generating plants. Thus, Mr. Nalepa stated that the only cost incurred by EGSL for reliability and flexibility is the commodity cost of the natural gas it purchases. Mr. Nalepa testified that EGSL achieves the same level of service as ETI without incurring the large cost of the Spindletop Facility. 177 Mr. Nalepa asserted that the long-term gas supply contract that ETI recently entered into with Enbridge Pipeline, L.P. (the Enbridge Contract) will help provide the Company with increased supply reliability because the gas supplied by Enbridge will come from production areas that are less susceptible to hurricane-related disruptions. Mr. Nalepa also noted that ETI could meet its swing flexibility requirements through use of spot gas purchases, its operational balancing agreement with the TETCO pipeline, and other pipeline companies, such as the Copano Pipeline that serves Lewis Creek. 178 Mr. Nalepa also disputed ETI's contention that the Spindletop Facility serves as a valuable protection against extreme events such as hurricanes, by noting that the Spindletop Facility was out of service for almost two weeks in 2005 following Hurricane Rita. 179 As noted above, Mr. Nalepa testified that it cost ETI $13,219,097 to operate the Spindletop Facility in the Test Year. Mr. Nalepa estimated that the sum of the Test Year withdrawals of gas from the Spindletop Facility equaled 8,560,604 MMBtu. He then divided his total estimated cost of the facility ($13,219,097) by his total estimated withdrawals of gas (8,560,604 MMBtu) to calculate an "all-in per unit rate" of $1.54 per MMBtu. He asserted that, by contrast, transportation costs on various gas pipelines connected to Sabine and Lewis Creek ranged from $0.025 to $0.22 per MMBtu. Mr. Nalepa estimated $0.18 per MMBtu as the average replacement cost that ETI would incur in transportation contracts if it were to stop using the Spindletop Facility and achieve the same 177 Cities Ex. 6 (Nalepa Direct) at 22-23. 178 Cities Ex. 6 (Nalepa Direct) at 25. 179 Id. at 23-24. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE66 PUC DOCKET NO. 39896 level of supply reliability and swing flexibility through the use of gas supply contracts. By multiplying $0.18 times 8,560,604 MMBtu, he estimated that the benefits of the Spindletop Facility could have been achieved through other means at a cost of only $1,724,659. Thus, Mr. Nalepa recommended that $7,794,202 should be removed from ETI's base rate, and $5,424,895 should be excluded as an eligible fuel expense. 180 ETI disagrees with essentially all of Mr. Nalepa' s points and responds to his testimony on a number of fronts. Perhaps foremost, ETI points out that Mr. Nalepa's main premise - that ETI's customers pay all the costs of the Spindletop Facility while the other Entergy operating customers avoid those costs - is simply incorrect. According to ETI witnesses, 57.50 percent of the costs associated with the Spindletop Facility are billed to EGSL as part of the MSS-4 billing process between ETI and EGSL for its "legacy plants," 181 and another 2.4 percent of the costs are passed on to other Entergy operating companies through the MSS-3 agreement. Only 40.1 percent of the Spindletop Facility costs are borne by ETI customers. 182 Thus, Mr. Nalepa's calculations greatly overstate the costs of the Spindletop Facility that are borne by ETI customers and greatly understate the costs that are borne by EGSL customers. ETI witness Considine also pointed out that the Commission has consistently and repeatedly concluded that the Spindletop Facility is used and useful and, therefore, has allowed ETI and its predecessors to recover the costs associated with the Spindletop Facility. 183 Ms. Mcllvoy also testified that, contrary to Mr. Nalepa's testimony, the conditions under which the other Entergy operating companies operate are so different from the conditions under which ETI operates that it makes no sense to assume they have similar supply reliability and swing flexibility needs. For example, EGSL and ETI both own roughly the same generating capacity from 180 Id. at 24-27; Cities Ex. 6B (Errata No. 2). 181 The legacy plants are the four power generating plants that were owned by Entergy Gulf States, Inc. - Lewis Creek, Sabine Station, Nelson, and Willow Glen. When EGSI was broken into ETI and EGSL in 2007, ETI became the owner of Lewis Creek and Sabine Station, while EGSL became the owner of Nelson and Willow Glen. ETI Ex. 60 (Mcllvoy Rebuttal) at 5-6; ETI Ex. 46 (Considine Rebuttal) at 3. 182 ETI Ex. 46 (Considine Rebuttal) at 3-4; ETI Ex. 60 (Mcllvoy Rebuttal) at 18-19. 183 ETI Ex. 46 (Considine Rebuttal) at 3-4. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE67 PUC DOCKET NO. 39896 gas-powered plants - 2,378 MW for EGSL versus 2,295 MW for ETI. However, the ETI plants are operated at a much higher capacity than the EGSL plants. During the Reconciliation Period, EGSL burned much less natural gas than did ETI- 63,420,554 MMBtu burned at the EGSL plants versus 144,538,535 MMBtu burned at the ETI plants. Moreover, EGSL has four gas-powered plants while ETI has only two. Of EGSL's four plants, two (Calcasieu and Ouachita) use combined cycle gas turbine technology. This gives them a quick-start and shut-down capability, allowing them to be operated primarily only at peak demand times. Thus, according to Ms. Mcllvoy, Mr. Nalepa's premise - that because EGSL is able to reliably operate its gas-fired facilities without gas storage, ETI should be able to do so as well - makes no sense. Because ETI bums a vastly larger amount of natural gas than EGSL, its need for supply reliability and swing flexibility is much greater. 184 Ms. Mcllvoy also disputed Mr. Nalepa' s assertion that ETI could use the Enbridge Contract and call options to provide the Company with sufficient supply reliability. She noted that the maximum amount of gas deliverable under the Enbridge Contract is insufficient to run the ETI plants even at minimum load. By contrast, the Spindletop Facility is capable of supplying all Sabine Station units and one unit at Lewis Creek for four days at 70 percent capacity. Moreover, the Enbridge Contract will expire, whereas the Spindletop Facility can be operated indefinitely. Ms. Mcllvoy explains that the use of call options is not viable because a call option must be delivered "ratably," meaning the gas must be delivered at a constant, even rate throughout the delivery period. In order to have gas available to meet peak needs in the absence of the Spindletop Facility, ETI would have to exercise call options for a maximum delivery, but it would not need all of the gas delivered at off-peak times of the day. 185 ETI witness Jaycox disputed Mr. Nalepa's premise that ETI could use call options to ensure reliability. According to Mr. Jaycox, "call options are cheaper than storage, but there's no comparison" between the amount of reliability that they provide as compared to the Spindletop Facility. 186 Mr. Jaycox also explained that, due to their geographic location and the limited import 184 ETI Ex. 60 (Mcllvoy Rebuttal) at 3-8. 185 ETI Ex. 60 (Mcllvoy Rebuttal) at 8-12. 186 Tr. at 969.  ··-~~------------------------ SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE68 PUC DOCKET NO. 39896 capability to the ETI service area, Sabine Station and Lewis Creek are considered particularly 187 critical, thereby increasing the need for reliability at those plants. When Mr. Nalepa calculated ETI' s cost of achieving supply reliability and swing flexibility without the use of the Spindletop Facility, he estimated it would cost only $1,724,659. He did so, in part, by assuming that a five-day 35,000 MMBtu/day call option would cost ETI $26,250. Ms. Mcllvoy asserted that it is not reasonable to assume that all options would cost as little as $26,250. Based upon her calculations, ETI would have to purchase 14 five-day 35,000 MMBtu/day call options per month to achieve supply reliability. She posited that, based upon the laws of supply and demand, the more call options ETI has to purchase, the higher the cost of those options would be. She also pointed out that Mr. Nalepa' s proposed use of call options would require ETI to spend hundreds of thousands of dollars each month to purchase call options that it would never exercise. According to Ms. Mcllvoy, it is unclear from Commission precedents whether ETI would be entitled to recover the costs of these un-exercised options. 188 The evidence establishes that the Spindletop Facility is critical to providing reliability and swing flexibility to ETI' s Texas plants. The AU s conclude that the Spindletop Facility is a used and useful facility providing reliability and swing flexibility to ETI' s customers at a reasonable price, and Cities' arguments to the contrary lack merit. I. Short Term Assets In its application ETI requested that, as short term assets, the following amounts be included in the rate base: prepayments in the amount of $7 ,218,037; materials and supplies in the amount of $29,252,574; and fuel inventory in the amount of $53,759,975. These amounts were derived using 13-month averages ending June 2011. 189 Staff witness Anna Givens agrees with the approach of using 13-month averages to determine the appropriate amounts for short term assets. However, she 187 Tr. at 975, 986-87. 188 ETI Ex. 60 (Mcllvoy Rebuttal) at 12-15. 189 ETI Ex. 3 at Sched. B-1. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE69 PUC DOCKET NO. 39896 recommends using the 13-month period ending December 2011, because it is the most recent information available. Using this approach, Ms. Givens recommends that, as short term assets, the following amounts be included in the rate base: prepayments at $8,134,351 ($916,313 more than ETI's request); materials and supplies at $29,285,421 ($32,847 more than ETI's request); and fuel inventory at $52,693,485 ($1,066,490 less than ETI's request). 190 ETI does not oppose Staff's recommendation on this issue. No party has a criticism of Staffs estimates as to prepayment, materials and supplies, and fuel inventory, nor do the ALls. Accordingly, the ALls recommend adopting the numbers proposed by Staff. J. Acquisition Adjustment In its application, ETI included an adjustment of $1,127,778 for an "electric plant acquisition." 191 The proposed adjustment, which relates to costs incurred by ETI when it acquired the Spindletop Facility, consists of closing costs of $211,209 and legal and internal costs of $916,568. 192 ETI witness Considine explained that, prior to December 2009, the same amounts were included in the Electric Plant in Service (FERC Account 101). On January 11, 2010, FERC issued Opinion No. 505 in FERC Docket No. ER07-956-00 and ordered the Company to transfer the amounts above from Account 101 to FERC Account 114, Electric Plant Acquisition Adjustments. He also pointed out that the costs were included in ETI's filed rate base amounts in Docket Nos. 34800 and 37744. 193 Mr. Considine contended that these amounts should remain in rate base because they represent costs incurred by ETI for the purchase of a viable asset that benefits its retail customers. He pointed out that the amounts have previously been included in the Company's rate base, but the only thing that has changed is that the amounts were previously allocated to a different account. ETI argues that the fact that the costs were approved as part of rate base in two previous ETI dockets verifies that they were "reasonable, prudently incurred, and properly capitalized." 194 190 Staff Ex. l (Givens Direct) at 3 l-32. 191 ETI Ex. 3 at Sched. C-l. 192 ETI Ex. 46 (Considine Rebuttal) at 4. 193 Id. at 4-5. 194 ETI Initial Brief at 43. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE70 PUC DOCKET NO. 39896 Thus, ETI contends it would be inappropriate to penalize it because of an accounting technicality 195 imposed upon it by FERC. Staff advocates the removal of the entire electric plant acquisition adjustment from rate base, contending that, "[a]s a rule, the rate base component for plant in service includes only the original cost, net of accumulated depreciation." 1% Cities similarly contend, without citing to any legal authority, that acquisition adjustments are not legally permitted as an addition to rate base for ratemaking purposes or as a depreciable asset for regulatory ratemaking purposes. 197 Staff disputes ETI' s contention that the fact that the costs were approved as part of rate base in two previous ETI dockets proves that they were reasonable, prudently incurred, and properly capitalized. Staff points out that those two prior dockets were settled rate cases and, therefore, "provide no illumination on this issue." 198 Finally, Staff argues that ETI failed to prove either element of the Commission's two- part Hooks test for the determination of whether the acquisition adjustment should be included in rate base. Pursuant to the Hooks test, in determining whether an acquisition adjustment should be included in rate base, "the Commission should consider whether or not the purchase price was excessive and whether or not specific and offsetting benefits have accrued to ratepayers." 199 According to Staff, ETI' s acquisition adjustment should be disallowed because the Company failed to meet it burden of proof on these two issues. 200 The AU s are unpersuaded by the arguments of Staff and Cities. Their primary argument (i.e., that acquisition adjustments are simply not allowed as an addition to rate base for ratemaking purposes) is incorrect. Indeed, the Hooks decision, the precedent on which Staff relies for its fallback argument, suggests that, more often than not, acquisition adjustments should be included in 195 ETI Ex. 46 (Considine Rebuttal) at 5. 196 Staff Ex. I (Givens Direct) at 35. 197 Cities Initial Brief at 26. 198 Stafflnitial Brief at IL 199 Application of Hooks Telephone Company for a Rate Increase within Bowie County, Docket No. 2150, Examiner's Report at 2 (Mar. 28, 1980)(Hooks). 200 Staff Reply Brief at 12. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE71 PUC DOCKET NO. 39896 rate base: "Amortization of an acquisition adjustment need not be allowed as an expense in all cases."201 Moreover, the evidence demonstrates that ETI met is burden under the Hooks test. As discussed more fully in Section V.H. of this PFD, above, there is ample evidence in the record to demonstrate that the Spindletop Facility is used and useful and provides specific and offsetting benefits to ratepayers in a cost-effective manner. The evidence further shows that the acquisition adjustment represents costs that were actually incurred by ETI in the furtherance of acquiring the Spindletop Facility, and not a mere mark-up in original cost. For these reasons, the ALls conclude that the $1,127,778 incurred by ETI in internal acquisition costs associated with the purchase of the Spindletop Facility was reasonable, necessary, and properly incurred. Accordingly, the ALl s agree that it should be included in ETI' s rate base. K. Capitalized Incentive Compensation In the application, some of the incentive payments ETI made to its employees were capitalized into plant in service accounts and ETI asks to include those amounts in rate base.202 A portion of those capitalized accounts represents payments made by ETI for incentive compensation tied to financial goals (financially-based incentive compensation). Cities contend that, consistent with Commission precedent, ETI ought not be allowed to include in rate base the portion of its capitalized incentive compensation that is attributable to financially-based incentive compensation. 203 The issue of whether financially-based incentive compensation is recoverable as a portion of Operating Expenses is discussed at length in Section VII.D.2. of this PFD. ETI makes the same arguments in favor of recoverability in that section that it makes here as to the inclusion of financially-based incentive compensation in rate base. The discussion of that issue need not be repeated here, but the analysis is the same. In summary, the ALls conclude that ETI should not be entitled to recover its financially-based incentive compensation costs. Thus, for the same reasons 201 Hooks (emphasis added). 202 Cities Ex. 2 (Garrett Direct) at 52. 203 Id. at 52-53. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE72 PUC DOCKET NO. 39896 discussed in Section VIl.D.2, the Al.Js agree with Cities' contention that the portion of ETI's incentive payments that are capitalized and that are financially-based should be excluded from ETI' s rate base. On the other hand, the Al.Js disagree with Cities as to the amount of that exclusion. Cities argue that $9,835, 111 (Cities' estimate of ETI' s financially-based incentive payments that are capitalized each year into plant in service) should be removed from rate base. 204 Broadly speaking, ETI has two categories of incentive compensation programs - annual incentive programs, and long- term incentive programs. To arrive at the figure of$9,835,1 l l, Cities' witness Garrett assumed that: (1) 100 percent of the costs of the long-term incentive programs were financially-based and, therefore, should be excluded from rate base; and (2) his calculated percentage of the annual incentive programs were financially-based and, therefore, should be excluded from rate base. He then applied those percentages to the incentive costs that ETI capitalized in 2008, 2009, and the portion of 2010 prior to the Test Year. 205 As explained in Section VII.D.2., the AUs agree that Mr. Garrett was correct to recommend removing 100 percent of the cost of ETI' s long-term incentive programs. However, as to the annual incentive programs, he defined what qualifies as "financially based" much too broadly, and therefore wrongly assumed that his calculated percentage of the costs of those programs should be excluded. Instead, the Al.J s conclude that the actual percentages should be used to determine the amount that is financially based. 206 Finally, ETI challenges Mr. Garrett's attempt to disallow capitalized incentive costs from 2008 through June 30, 2009. Much of the rate base that Mr. Garrett seeks to disallow (namely, costs from 2007 through June 30, 2009) is not presented for review in this rate case. Rather those costs were presented for review in the Company's last rate case, Docket No. 37744, 204 Id. at 52-53; Cities Initial Brief at 27. 205 Cities Ex. 2 (Garrett Direct) at 53 and MG-2.10. 206 See discussion in Section VII.D.2. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE73 PUC DOCKET NO. 39896 in which the Company presented capital additions for the period of April 1, 2007, through June 30, 2009 .... Even though Docket No. 37744 was a settled case, the final order concluded that '[b ]ased on the evidence in this docket, the overall total invested capital through the end of the test year meets the requirements in PURA § 36.053(a) that electric utility rates be based on original cost, less depreciation of property used and useful to the utility in providing service.' This conclusion goes beyond merely settling issues without deciding anything and should be construed as to be conclusive as to the reasonableness of capital costs at issue in that prior case. 207 The ALls agree. The Test Year for ETI's prior ratemaking proceeding ended on June 30, 2009. The reasonableness of ETI' s capital costs (including capitalized incentive compensation) was dealt with by the Commission in that proceeding and is not at issue here. Thus, the ALls conclude that exclusion of capitalized incentive compensation that is financially-based can only be made 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). The amount of the exclusion is not specifically known at this time. VI. RATE OF RETURN [Germane to Preliminary Order Issue Nos. 4and11] A. Capital Structure ETI's capital structure is 50.08 percent debt and 49.92 percent equity. No party has taken issue with ETI's capital structure. Therefore, the ALls recommend that the Commission enter an order finding that the appropriate capital structure for ETI is 50.08 percent debt and 49.92 percent equity. B. Return on Equity The United States Supreme Court has set forth a minimum constitutional standard governing equity returns for utility investors: From the investor or company point of view it is important that there be enough revenue not only for operating expenses but also for the capital costs of the business. These include service on the debt and dividends on the stock. By that standard the 207 ETI Initial Brief at 44, quoting Docket No. 37744, Order at CoL 10 (Dec. 13, 2010). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE74 PUC DOCKET NO. 39896 return to the equity owner should be commensurate with returns on investments in other enterprises having comparable risks. That return, moreover, should be sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and to attract capital. 208 Thus, a utility must have a reasonable opportunity to earn a return that is: (1) commensurate with returns on equity investments in enterprises having comparable risks; (2) sufficient to ensure the financial soundness of the utility's operations; and (3) adequate to attract capital at reasonable rates, thereby enabling it to provide safe, reliable service. The allowed ROE should enable the utility to finance capital expenditures at reasonable rates and to maintain its financial flexibility during the period in which the rates are expected to remain in effect. 1. Proxy Group Because ETI is not a publicly traded company, it is necessary to establish a group of companies that are publicly traded and that are comparable to ETI in certain fundamental business and financial respects to serve as its "proxy" in the ROE estimation process. Both financial theory and legal precedent support the use of comparable companies within a proxy group to determine a utility's ROE, and all of the ROE witnesses in this case have relied on proxy groups to estimate a required ROE for ETI. ETI witness Hadaway started with all the vertically integrated electric utilities that are included in the Value Line Investment Survey (Value Line). To improve the group's comparability with ETI, which has a senior secured bond ratings of BBB+ (Outlook Negative) from Standard & 208 Federal Power Comm'n v. Hope Natural Gas Co., 320 U.S. 591, 603, 64 S. Ct. 281, 288 (1944); see also Bluefield Waterworks &Improvement Co. v. Public Serv. Comm'n ofW. Va., 262 U.S. 679, 692-93, 43 S. Ct. 675, 679 (1923) ("A public utility is entitled to such rates as will pennit itto earn a return on the value of the property which it employs for the convenience of the public equal to that generally being made at the same time and in the same general part of the country on investments in other business undertakings which are attended by corresponding risks and uncertainties; but it has no constitutional right to profits such as are realized or anticipated in highly profitable enterprises or speculative ventures. The return should be reasonably sufficient to assure confidence in the financial soundness of the utility and should be adequate, under efficient and economical management, to maintain and support its credit and enable it to raise the money necessary for the proper discharge of its public duties."). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE75 PUC DOCKET NO. 39896 Poor's (S&P) and Baa2 (stable) rating from Moody's Investors Service (Moody's), Dr. Hadaway imposed the following restrictions: • comparable companies had to have senior secured bond ratings of at least BBB by S&P or Baa by Moody's; • comparable companies had to derive at least 70 percent of revenues from regulated utility sales; • comparable companies had to have consistent financial records not affected by recent mergers or restructuring; and • comparable companies had to have a consistent dividend record with no dividend cuts or resumptions during the past two years. Those selection criteria resulted in a 23-utility proxy group. State Agencies witness Miravete excluded Entergy from his proxy group, but otherwise his proxy group was identical to ETI' s. Cities witness Parcell ran his calculations using both Dr. Hadaway' s 23-utility proxy group and another 8-utility proxy group, but they produced similar ROE results. TIEC witness Gorman used the same 23 utility proxy group as ETI witness Hadaway used. Staff witness Cutter was the only witness to use a different proxy group. He used a 13 utility proxy group for his discounted cash-flow (DCF) analysis. To arrive at this proxy group, Mr. Cutter started with all of the domestic electric-utility companies tracked by Value Line because Value Line is the most widely used, independent investment service in the world. Then he eliminated the utilities that did not meet the following criteria: • Value Line Financial Strength ratings of A+, A or B++; • A capital structure including less than 45 percent, or more than 55 percent, debt; • Total capitalization in excess of five billion dollars; • No recent dividend cuts or omissions; SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE76 PUC DOCKET NO. 39896 • No recent or potential merger activities or other major capital expansion; and • No Value Line appraisal of being outside the norm. On his final analysis, Mr. Cutter eliminated three of his 13 utility proxy group, referring to those he eliminated as "outliers." ETI points out, however, that one of the remaining ten companies, Con Ed, is not comparable to ETI because it is a delivery company as opposed to a vertically integrated utility. ETI' s essential criticism of Mr. Cutter's proxy group analysis is that he should have used a larger proxy group and that he admitted a better comparison to ETI could be obtained from using a larger proxy group. 2. DCF Analysis To analyze ETI's cost of equity capital, all of the testifying experts first performed a DCF analysis. The DCF approach is based on the theory that a stock's current price represents the present value of all expected future cash flows. In its most general form, the DCF model is expressed as follows: D1 D2 D 00 Po = (1 + k) + (1 + k) + (1 + k) Where Po represents the current stock price, D1 • ••• Doo are all expected future dividends, and k is the expected discount rate, or required ROE. That equation can be simplified and rearranged to ascertain the required ROE: D(l + g) k= +g Po Where Po represents the current stock price, Dis expected future dividends, g is the growth rate, and k is the expected discount rate, or required ROE. This is commonly referred to as the "Constant Growth DCF' model in which the first term is the expected dividend yield and the second term is the expected long-term growth rate. The SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE77 PUC DOCKET NO. 39896 Constant Growth DCF model requires assumptions of: (1) a constant growth rate for earnings and dividends; (2) a stable dividend payout ratio; (3) a constant price-to-earnings multiple; and (4) a discount rate greater than the expected growth rate. ETI witness Hadaway' s DCF analysis was based on three versions of the DCF model. In the first version of the DCF model, he used the constant growth format with long-term expected growth based on analysts' estimates of five-year utility earnings growth. In the second version of the DCF model, for the estimated growth rate, Dr. Hadaway used only the long-term estimated gross domestic product (GDP) growth rate. In the third version of the DCF model, Dr. Hadaway used a two-stage growth approach, with stage one based on Value Line's three-to-five-year dividend projections and stage two based on long-term projected growth in GDP. The dividend yields in all three of the annual models are from Value Line's projections of dividends for the coming year and stock prices are from the three-month average for the months that correspond to the Value Line editions from which the underlying financial data are taken. 209 The DCF results for Dr. Hadaway' s comparable company group using the traditional constant growth model indicated an ROE of 9. 90 percentto 10.00 percent. Dr. Hadaway then recalculated the constant growth results with the growth rate based on long-term forecasted growth in GDP. With the GDP growth rate, the constant growth model indicates an ROE range of l 0.40 percent to 10.70 percent. Although the GDP growth rate is higher than the average of analysts' growth rates, Dr. Hadaway testified that his GDP estimate is within the analysts' range and slightly below the 6.00 percent 3-to-5 year average growth rate projection from Value Line. Finally, Dr. Hadaway's multistage DCF model indicated an ROE range of 10.20 percent to 10.30 percent. The results from the DCF model, therefore, indicate an ROE range of 9. 90 percentto 10. 70 percent.210 In his rebuttal, Dr. Hadaway updated his ROE analysis using current market conditions but employing the same methodologies that he used in his previous analysis. After making adjustments to the proxy group to 209 ETI Ex. 6 (Hadaway Direct) at 33-44. 210 Id. at 44, Exhibit SCH-4. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE78 PUC DOCKET NO. 39896 stay consistent with his selection criteria, Dr. Hadaway' s indicated DCF range was 10.00 percent to 10.20 percent. 211 The principal argument against Dr. Hadaway's analyses is that he used unsupported and excessive growth rates. According to the intervenors, these excessive growth rates exaggerate future cash flows, which results in an inflated ROE. Intervenors argue that Dr. Hadaway' s Analysts' Constant Growth DCF model produces excessive return estimates.212 In rebuttal, Dr. Hadaway's analysts' growth model produced a 10.1 percent group average ROE and a 10.0 percent group median ROE. 213 The intervenors contend that the group average long-term growth rate on which his DCF study was based was 5.62 percent, which is far too high to be sustainable in the long-term (as required as an input in the Constant 214 Growth DCF model). According to intervenors, the excessive level of his growth rate is apparent by comparison to current analysts' projected growth for U.S. GDP, which range from 4.5 percent to 5.0 percent. 215 Dr. Hadaway's growth rate is more than 60 basis points above the most generous expected growth of the U.S. economy. Intervenors contend that that nominal GDP should be the ceiling of a reliable proxy for a utility dividend growth rate. Because the evidence shows that nominal GDP as projected by consensus analysts, the Executive Branch, and the Congressional Budget Office is 5 percent, Dr. Hadaway' s 5.62 percent growth rate is excessive and undermines the reasonableness of his models. Intervenors criticize Dr. Hadaway's decision on rebuttal to exclude Edison International in 216 his proxy group. Dr. Hadaway did so because Edison International's ROE of 5.2 percent was below a 5.07 percent cost of debt based on an average of Triple B utility rates for the time period 211 Id. at 44. 212 TIEC Ex. 2 (Gorman Direct) at 39. 213 ETI Ex. 52 (Hadaway Rebuttal) at Ex. SCH-R-6. 214 Id. at Ex. SCH-R-6; TIEC Ex. 2 (Gorman Direct) at 39; Cities Ex. 3 (Parcell Direct) at 36-37; OPC Ex. 1 (Szerszen Direct) at 23-24. 215 TIEC Ex. 2 (Gorman Direct) at 19; Cities Ex. 3 (Parcell Direct) at 37. 216 ETI Ex. 51 (Hadaway Rebuttal) at Ex. SCH-R-6. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE79 PUC DOCKET NO. 39896 January 12-March 12, plus 100 basis points. 217 Intervenors contend that this rationale is tenuous, and that had Dr. Hadaway included Edison International (or even excluded Hawaiian Electric, the utility in his proxy group that had the highest ROE) his own analysis (even with its excessive growth rates) would have resulted in a 9.85 percent average ROE. Finally, Dr. Hadaway conceded that he used the same methodology for calculating GDP in this case as he did in the Oncor rate case. 218 Intervenors contend that Dr. Hadaway's GDP projections are not credible proxies for investor's expected dividend growth rates because they are not based on published analysts' or government GDP forecasts. Rather, Dr. Hadaway forecasts future GDP growth using his own personal calculation that forecasts GDP by examining historic GDP growth over the last 10, 20, 30, 40, 50, and 60-year periods and weighting those averages. 219 Intervenors note that this approach was rejected by the Commission in the Oncor rate case. 220 Staff witness Cutter used the DCF model to project ETI' s cost of equity. Under Mr. Cutter's view, the theory underlying the DCF model is that the price of a share is equal to the present value of all future earnings. Unless the stock is sold for a profit (or loss) from the price it was originally purchased, the only way to determine earnings on a share is to determine its future dividends. This requires, in Mr. Cutter's opinion, an understanding of investors' current expectations of growth of those dividends. The issue is the growth expectation that investors have embodied in the current price of the stock. According to Mr. Cutter, the best way to arrive at a reliable growth estimate of those dividends is to use the growth estimates of investment advisory firms rather than the estimates of a single, independent analyst. 221 Mr. Cutter used both Value Line and Zacks Investment Service (Zacks) in ascertaining long-term earnings growth rates. He used Value Line because it is the most widely used independent 211 Id. 218 Tr. at 227-228. 219 ETI Ex. 6 (Hadaway Direct) at Ex. SCH-3; Tr. at 218. 220 Application of Oncor Electric Delivery Company, UC, for Authority to Change Rates, Docket No. 35717, PFD at 72-73.  ~ ·--------------- SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE SO PUC DOCKET NO. 39896 investment service in the world and Zacks because it compiles consensus earnings forecasts from 222 groups of professional security analysts. Mr. Cutter's DCF analysis resulted in range from 7.46 percent to 10. 71 percent, with a point estimate for cost of equity being 9.3 percent. TIEC witness Gorman' s first DCF model was a constant growth model using consensus analysts' growth rates that resulted in an average constant growth DCF of 9 .32 percent and a median constant growth DCF of 9.84 percent. The average analysts' growth rate was 4.94 percent. 223 According to TIEC, ETI does not claim that a constant growth model using analysts' growth rates is inappropriate and argues that Dr. Hadaway failed to offer any rebuttal testimony criticizing Mr. Gorman's Analysts' Growth DCF model. Mr. Gorman also performed a constant growth DCF model using sustainable growth rates. His average sustainable growth rate for the proxy group was 4.54 percent and produced a proxy group average and median DCF result of 8.91 percent and 8.9 percent, respectively. 224 According to TIEC, a sustainable growth rate is based on the percentage of a utility's earnings that are retained and reinvested in utility plant and equipment. 225 Mr. Gorman also performed a multi-stage DCF model to reflect changing growth expectations that would reflect the possibility of non-constant growth for a company over time. Mr. Gorman's multi-stage model reflected three growth periods: (1) a short-term growth period of five years; (2) a transition period for years six through ten; and (3) a long-term growth period, starting in year 11 through perpetuity. For the short-term period, Mr. Gorman relied on the consensus analysts' growth projections from his constant growth DCF model (i.e., 4.94 percent). For 221 Staff Ex. 6 (Cutter Direct) at 10-15. 222 Staff Ex. 6 (Cutter Direct) at 13. 223 TIEC Ex. 2 (Gorman Direct) at Ex. MPG-4. 224 TIEC Ex. 2 (Gorman Direct) at 18. 225 TIEC Ex. 2 (Gorman Direct) at 17. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE81 PUC DOCKET NO. 39896 the second stage (i.e., the transition period), growth rates are reduced or increased by an equal factor, which reflect the difference between the analysts' growth rates and the GDP growth rate. For the long-term period, he assumed the maximum sustainable growth rate for a utility company as proxied by the consensus analysts' projected growth rate for the U.S. GDP (i.e., 5.0 percent). The result of his multi-stage growth DCF model was an average ROE of 9.37 percent and a median of 9.48 percent. 226 Cities witness Parcell calculated the DCF results for each company in his proxy group by using and considering five indicators of growth expectations consisting of: (i) 2007 -2011 earnings retention; (ii) five-year historical average earnings per share, dividends per share, and book value per share; (iii) projected earnings retention; (iv) projected EPS, DPS, BVPS; and (v) projected EPS as reported by Yahoo Finance. Using this in his DCF model resulted in an ROE of 9.0 percent to 9 .5 percent. 227 OPC witness Szerszen' s DCF analysis used the same group of 23 comparable companies included in Dr. Hadaway's DCF analysis. Dr. Szerszen's DCF analysis was framed with consideration of ETI' s financial integrity as discussed by the major bond rating agencies, the current and projected interest rate environment, and investment analyst views of the regulated utility sector. 228 Interest rates are currently very low, as reflected in the yields to maturity and interest rates on various fixed income investments. OPC contends, in contrast to Dr. Hadaway, that utility stocks have been less volatile than the stock market in general.2 29 This is confirmed by Value Line's December 23, 2011, observation that "electric utility stocks have long been viewed as a safe haven in volatile markets, due in large part to their generous dividend yields."230 Dr. Szerszen also took exception to Moody's characterization of ETI as having above average business and regulatory risk. Moody's assessment is primarily based on the lack of pass-through regulatory lag-reducing cost 226 TIEC Ex. 2 (Gorman Direct) at 19, Ex. MPG-9. 227 Cities Ex. 3 (Parcell Direct) at 24, 33. 228 OPC Ex. l (Szerszen Direct) at 8-17. 229 Id. at 15. 230 Id. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE82 PUC DOCKET NO. 39896 recovery mechanisms in Texas compared to Entergy's Louisiana and Mississippi jurisdictions. Dr. Szerszen testified that ETI may not have a formula rate plan similar to the Louisiana and Mississippi Entergy operating companies, but it does have a Distribution Cost Recovery Factor (DCRF) and Transmission Cost Recovery Factor (TCRF) available that "will allow ETI to charge ratepayers for additional distribution and transmission investments outside of a traditional rate request filing."231 None of Entergy' s other operating companies have TCRF and DCRF riders. OPC notes that Cities witness Parcell agrees that the availability of such recovery mechanisms affects ETI' s level of risk; he testified that a combination of ETI' s fuel factor rider, TIC rider, energy efficiency rider, hurricane cost recovery rider, rate case expense rider, proposed increased customer service charge, and DCRF and TCRF riders results in about 30 percent of ETI' s total overall requested revenue requirement being subject to revenue risk and regulatory lag. 232 Dr. Szerszen incorporated two different dividend yield calculations in her DCF model. The first calculation estimated a dividend yield using 2011 average stock prices and 2012 projected dividend rates for each company, and the second calculation incorporated more recent March 5, 2012, closing prices for the comparables. The average dividend yield using 2011 average stock prices was 4.66 percent and, using March 5, 2012, closing prices, was 4.32 percent.233 Dr. Szerszen provided some practical examples of how blind reliance on analyst earnings growth projections can lead to questionable DCF growth rates. At least five of the comparable utility companies had five-year earnings growth rate projections that ranged from 8.5 percent to 11 percent. Dr. Szerszen stated that she was unaware of any regulated utility company that has consistently achieved such high earnings growth rate over the past 28 years, and that it is reasonable to assume such performance is unlikely in the longer term future. Dr. Szerszen's review of the comparable company past and projected growth rates resulted in a reasonable dividend growth rate expectation of 3.9 percent to 5 percent. Depending on whether 2011 average stock prices are used or the updated 231 Id at 11-13. 232 Cities Ex. 3 (Parcell Direct) at 16-18. 233 OPC Ex. 1 (Szerszen Direct) at 17. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE83 PUC DOCKET NO. 39896 2012 stock prices are used, Dr. Szerszen's DCF analysis resulted in an ROE ranging from 8.32 percent to 9.32 percent.234 State Agencies' witness Miravete's DCF analysis used calculations for three averaging periods, 30, 90 (the reference period), and 180 days ending on March 2, 2012, respectively. For the commonly used 90 day averaging period, the capitalization-weighted average ROE is 9.23 percent. Evaluating the averaging period at either 30or180 days produces ROE estimates of9.24 percent and 9.34 percent, respectively. Dr. Miravete weighed the computations by the capitalization of each firm to correct the effect of each variable according to the relative market value of the corresponding utility. According to Dr. Miravete, this approach avoids the distortion caused by adding numerous, but possibly irrelevant, firms that may produce biased estimates. Dr. Miravete conceded that the effect of ignoring differences in scale of utilities in the determination of the ROE is substantial. He acknowledged that if he had ignored the differences in size of these electric utilities, his DCF ROE estimate would have been 9 .68 percent. 235 3. Risk Premium Analysis Dr. Hadaway's risk premium studies are divided into two parts. First, he compared electric utility authorized ROEs for the period 1980-2010 to contemporaneous long-term utility interest rates. The differences between the average authorized ROEs and the average interest rate for the year is the indicated equity risk premium. He then added the indicated equity risk premium to the forecasted and current triple-B utility bond interest rate to estimate ROE. 236 In calculating the equity risk premium, Dr. Hadaway adjusted for the inverse relationship between equity risk premiums and interest rates (when interest rates are high, risk premiums are low and vice versa). Dr. Hadaway provided regression analyses of the allowed annual equity risk premiums relative to interest rate levels. The negative regression coefficients confirm the inverse 234 Id. at 22. 235 State Agencies Ex. 1 (Miravete Direct) at 12-13. 236 ETI Ex. 6 (Hadaway Direct) at 36-38, 45. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE84 PUC DOCKET NO. 39896 relationship between equity risk premiums and interest rates according to ETI. Dr. Hadaway used that negative interest rate change coefficient in conjunction with current and forecasted interest rates to establish the appropriate ROE. 237 Staff witness Cutter agreed that the risk premium analysis needs to reflect this adjustment. 238 The results of Dr. Hadaway' s initial equity risk premium studies indicate an ROE range of 10.00 percent to 10.01 percent. ETI states that these results reflect the sharp drop in interest rates that have occurred for high quality borrowers. The Federal Reserve System's continuing "easy money" policies have provided renewed liquidity in the credit markets that is reflected in these lower yields. These models, however, cannot capture the current equity volatility or the increased level of risk aversion for equity investors. These circumstances indicate that the cost of equity has not declined to the extent that interest rates on utility debt have dropped. Thus, Dr. Hadaway testified that the results of the risk premium analysis must be discounted and more emphasis placed on the 239 DCF analysis. In his rebuttal, Dr. Hadaway updated his ROE analysis using current market conditions but employing the same methodologies that he used in his previous analysis. 240 His updated risk premium analysis was an ROE of 10.38 percent using projected triple-B utility interest rates and 9.96 percent using current triple-B utility interest rates. 241 TIEC contends that Dr. Hadaway' s utility risk premium analysis is flawed for two primary reasons. First, Dr. Hadaway developed a forward-looking risk premium model that relied on forecasted interest rates and volatile utility spreads that are uncertain and produce inaccurate results. As Mr. Gorman testified, it is more reasonable at this time to rely on current observable interest rates rather than forecasted projections. Over the last several years, forecasted yield projections have 237 ETI Ex. 6 (Hadaway Direct) at 45-46, Ex. SCH-5; ETI Ex. 52 (Hadaway Rebuttal) at 32. 238 Staff Ex. 6 (Cutter Direct) at 20. 239 ETI Ex. 6 (Hadaway Direct) at 10-23, 45; Tr. at 233-235. 240 ETI Ex. 52 (Hadaway Rebuttal) at 44. 241 Id. at 45. SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE85 PUC DOCKET NO. 39896 proven to be overstated because, even though interest rates have been projected to increase, those projections have consistently been proven wrong. 242 Accordingly, Dr. Hadaway' s forecasted utility bond yield of 5.17 percent is overstated. Second, TlEC argues that Dr. Hadaway's risk premium model is flawed because he improperly inflates his actual risk premium of 3.28 percent with an adjustment of 1.56 percent that he asserts reflects the inverse relationship between interest rates and utility risk premiums. 243 TlEC argues that Dr. Hadaway's use of this adjustment is improper and not supported by academic research. Mr. Gorman testified that "a relative investment risk differential cannot be measured simply by observing nominal interest rates."244 He noted: While academic studies have shown that, in the past, there has been an inverse relationship with these variables, researchers have found that the relationship changes over time and is influenced by changes in perception of the risk of bond investments relative to equity investments, and not simply changes to interest rates. 245 As described in Mr. Gorman's testimony, correcting Dr. Hadaway's models for the elimination of this inverse relationship adjustment puts Dr. Hadaway' s risk premium in the range of 8.5 percent to 10 percent, with a midpoint of 9.3 percent. 246 Staff witness Cutter's "conventional risk premium estimate" estimated the cost of ETI's equity by comparing the costs of equity authorized for utilities across the United States to the yields of large-company corporate bonds that are rated Baa by Moody's within the timeframe of 1980 through 2011. This risk premium approach relies on the historical relationship between two indices 242 TIEC Ex. 2 (Gorman Direct) at 42-43; OPC Ex. !(Szerszen Direct) at 27-28. 243 TIEC Ex. 2 (Gorman Direct) at 42-43; see also ETI Ex. 6 (Hadaway Direct) at Ex. SCH-5 at 1. 244 TIEC Ex. 2 (Gorman Direct) at 44. 245 TIEC Ex. 2 (Gorman Direct) at 44 (citing "The Market Risk Premium: Expectational Estimates Using Analysts' Forecasts," Robert S. Harris and Felicia C. Marston, Journal ofApplied Finance, Volume 11, No. 1, 2001 and "The Risk Premium Approach to Measuring a Utility's Cost of Equity," Eugene F. Brigham, Dilip K. Shome, and Steve R. Vinson, Financial Management, Spring 1985). 246 TIEC Ex. 2 (Gorman Direct) at 45. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE86 PUC DOCKET NO. 39896 to forecast a value for one of the indices in a period for which it is unknown by using the known 247 value of the other one during that same period. To account for the relationship between the authorized costs of equity and the bond yields required to quantify ETI's cost of equity, Mr. Cutter subtracted the bond yields from the authorized costs of equity to determine a risk premium for the riskier equity. He tested the data by performing a regression analysis, which showed with high confidence that there is a trend in the relationship. It is an inverse trend, in which the risk premiums increase as bond yields decrease. On average, from 1980 to 2011, risk premiums increased 0.4207 percent for every 1.00 percent that bond yields 248 decreased. The calculation of the adjustment to the risk premium that the regression analysis indicated was incorporated in Staffs analysis. The results of this risk premium analysis produced a cost of equity of 9.81 percent. 249 Mr. Gorman' s risk premium analysis produced an ROE estimate in the range of 9.2 percent to 9 .4 percent, with a midpoint estimate of approximately 9 .3 percent. His risk premium model was based on two estimates of an equity risk premium. First, he estimated the difference between the required return on utility common equity investments and U.S. Treasury bonds for the period 1986 through 2011, which produced an equity risk premium of 5.23 percent. The second equity risk premium estimate was based on the difference between regulatory commission-authorized returns on common equity and contemporary "A" rated utility bond yields for the period 1986 through 2011, which produced an equity risk premium of 3.8 percent. Mr. Gorman testified that "[t]he equity risk premium should reflect the relative market perception of risk in the utility industry today." 250 247 Staff Ex. 6 (Cutter Direct) at 10, 19. 248 Staff Ex. 6 (Cutter Direct) at 20. 249 Id. at 20, Attachment SC-6. 250 TIEC Ex. 2 Gorman Direct) at 26. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE87 PUC DOCKET NO. 39896 Accordingly, to gauge investor expectations he examined the yield spread between utility bonds and Treasury bonds over the last 32 years. 251 According to TIEC, this analysis showed that the current utility bond yield spreads over Treasury bond yields are lower than the 32-year average spreads, which is evidence that "the market considers the utility industry to be a relatively low risk investment and demonstrates that utilities continue to have strong access to capital."252 Mr. Gorman then added a projected long-term Treasury bond yield to his estimated equity risk premium over Treasury yields, which produced a common equity in the range of 8.2 percent to 9.95 percent. Due to unusually large yield spreads between Treasury bond and "Baa" utility bond yields, Mr. Gorman gave two-thirds weight to his high end risk premium of 9.95 percent and one-third weight to his low-end risk premium of 8.2 percent, which produced an equity risk premium of 9 .4 percent. He also added his equity risk premium over utility bond yields to the current 13-week average yield on "Baa" rated utility bonds for the period ending March 2, 2012, of 5.05 percent. Adding his equity risk premium of 3.03 percent to 4.62 percent to the bond yield of 5 .05 percent, produced an ROE in the range of 8.08 percent to 9 .67 percent, which he then weighted more heavily on the high end estimate to produce a recommendation of 9 .2 percent. 253 The primary criticism that Dr. Hadaway lodged against Mr. Gorman' s risk premium analysis was that Mr. Gorman did not adjust his analysis upward to reflect a purported inverse relationship between equity risk premiums and interest rates. 254 For example, Dr. Hadaway's risk premium analysis adjusted his risk premium results by 1.56 percent to account for this relationship. 255 OPC witness Szerszen also performed a risk premium analysis, using Dr. Hadaway' s study of historical authorized electric company allowed returns on equity and average bond yields. The 251 Id. at 25-28. 252 Id. at 27. 253 TIEC Ex. 2 (Gonnan Direct) at 26-28. 254 ETI Ex. 52 (Hadaway Rebuttal) at 32. 255 ETI Ex. 6 (Hadaway Direct) at Ex. SCH-5. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE88 PUC DOCKET NO. 39896 average risk premium from Dr. Hadaway's 1980-2010 study was 328 basis points.256 Adding this historical risk premium to current triple B bond yield (4.67 percent) results in a 7.95 percent risk-premium derived DCF rate, and using Dr. Hadaway' s 5 .17 percent projected bond yield results in a risk premium derived rate of 8.45 percent. Giving more weight to the 2001-2010 risk premiums shown in Dr. Hadaway's exhibit results in an average risk premium of 4.21 percent. This yields an 8.88 percent to 9.38 percent risk premium derived cost of equity based on the current 4.67 percent and projected 5.17 percent bond yields, according to Dr. Szerszen's analysis.2s 7 4. Comparable Earnings Cities witness Parcell also performed a Comparable Earnings analysis. According to Mr. Parcell, the Comparable Earnings method is derived from the "corresponding risk" standard of the Bluefield and Hope cases. This method is thus based upon the economic concept of opportunity cost. The cost of capital is an opportunity cost: the prospective return available to investors from alternative investments of similar risk. 258 The Comparable Earnings method is designed to measure the returns expected to be earned on the original cost book value of similar risk enterprises. Thus, according to Mr. Parcell, this method provides a direct measure of the fair return, because the Comparable Earnings method translates into practice the competitive principle upon which regulation is based. 259 The Comparable Earnings method normally examines the experienced and/or projected returns on book common equity. The logic for examining returns on book equity follows from the use of original-cost, rate-base regulation for public utilities, which uses a utility's book common equity to determine the cost of capital. This cost of capital is, in tum, used as the fair rate of return which is then applied (multiplied) to the book value of rate base to establish the dollar level of 256 ETI Ex. No. 6 (Hadaway Direct) at Ex. SCH-5. 257 OPC Ex. 1 (Szerszen Direct) at 29-30. 258 Cities Ex. 3 (Parcell Direct) at 28. 259 Id. at 29. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE89 PUC DOCKET NO. 39896 capital costs to be recovered by the utility. Mr. Parcell stated that this technique is thus consistent with the rate base methodology used to set utility rates. 260 Mr. Parcell conducted the Comparable Earnings methodology by examining realized returns on equity for several groups of companies and evaluating the investor acceptance of these returns by reference to the resulting market-to-book ratios. He testified that in this manner it is possible to assess the degree to which a given level of return equates to the cost of capital. Mr. Parcell's Comparable Earnings analysis is based on market data (through the use of market-to-book ratios) and is thus essentially a market test. As a result, he testified that his analysis is not subject to the criticisms occasionally made by some who maintain that past earned returns do not represent the cost of capital. In addition, he stated that his analysis uses prospective returns and thus is not confined to historical data. 261 Mr. Parcell' s Comparable Earnings analysis considered the experienced equity returns of the proxy groups of utilities for the period 1992-2011 (i.e., the last twenty years). His Comparable Earnings analysis required an examination of a relatively long period of time to determine trends in earnings over at least a full business cycle. Further, in estimating a fair level of return for a future period, it is important to examine earnings over a diverse period of time to avoid any undue influence from unusual conditions that may occur in a single year or shorter period. Therefore, in forming his judgment of the current cost of equity he focused on two periods: 2002-2011 (the recent business cycle) and 1992-2001 (the prior business cycle). 262 Based on the recent earnings and market-to-book ratios, Mr. Parcell' s Comparable Earnings analysis indicated that the cost of equity for the proxy utilities is no more than 9.5 percent to 10.0 percent (9.75 percent mid-point). Recent returns of 10.0 percent to 12.1 percent have resulted in market-to-book ratios of 143 and greater. Prospective returns of9.5percentto10.3 percent result 260 Id. 261 Cities Ex. 3 (Parcell Direct) at 29. 262 Id. at 30. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE90 PUC DOCKET NO. 39896 in anticipated market-to-book ratios of over 125. As a result, it is apparent that returns below this level would result in market-to-book ratios of well above 100. According to Mr. Parcell, an ROE of 9.5 percent to 10.0 percent should thus result in a market-to-book ratio of well over 100 .263 5. CAPM Analysis The Capital Asset Pricing Model (CAPM) is a risk premium approach that estimates the ROE for a given security as a function of a risk-free return plus a risk premium to compensate investors for the non-diversifiable, or systematic, risk of that security. The CAPM formula is as follows: Where Ke equals the required market ROE; f3 equals the Beta of an individual security; r1equals the risk free rate of return; and rm equals the required return on the market as a whole. In this equation, (rm - r1) represents the market risk premium. According to the theory underlying the CAPM, because diversifiable risk can be diversified away, investors should be concerned only with non-diversifiable risk, which is measured by Beta. In effect, Beta represents the risk of the particular security relative to the market as a whole. Only Staff witness Cutter, Cities witness Parcell, and State Agencies witness Miravete used the CAPM methodology to estimate ETI's ROE. Mr. Cutter used CAPM in the qualitative analysis of ETI' s cost of equity. He did not directly use the CAPM in the determination of ETI' s cost of equity because it yielded a cost of equity that was over 200 basis points lower than the lower of the other two estimates, while those other two estimates were less than half a percent apart from each other. 264 The CAPM provides an additional indication that a significant drop to the estimated costs of equity that Staff made in prior dockets is 263 Cities Ex. 3 (Parcell Direct) at 31-32. 264 Staff Ex. 6 (Cutter Direct) at 21. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE91 PUC DOCKET NO. 39896 appropriate because the CAPM estimate is lower than either of the two other approaches even when adjusted for the current low yield on Treasury Bonds. 265 Mr. Cutter testified that the CAPM is one of the cornerstones of financial theory. 266 In its simplest sense, the model describes the relationship between the risk of an asset and its expected return, and assumes that investors will not hold a risky asset unless they are adequately compensated for the risk. 267 In this case, without any adjustment to the way it has been used in recent rate cases at the Commission, the CAPM yielded a cost of equity for ETI of 6.93 percent. Mr. Cutter testified that aspects of the capital markets today were likely causing the CAPM's cost of equity estimate to be low. Specifically, the Federal Reserve System is following an aggressive policy designed to keep the yields of both short-term and long-term Treasury bonds low. This policy influences two of the three variables used in the CAPM formula to be lower, which, in tum, makes the CAPM's final estimate of ETI' s cost of equity lower. 268 To account for the impact of this aggressive Federal Reserve System policy, Mr. Cutter made two adjustments to his CAPM analysis. First, Mr. Cutter adjusted the risk-free rate variable in the CAPM because it is most influenced by current Federal Reserve System policy. By changing this variable to 3.7 percent (which is the average yield from 1926 through 2010 of the risk-free rate's proxy security, U.S. Treasury Bills), the CAPM's estimate of ETI's cost of equity increased from 6.93 percent to 7.92 percent, or by 99 basis points. 269 The second adjustment to the CAPM result that Mr. Cutter made to account for the current aggressive Federal Reserve System policy was to the risk premium, which is also particularly 265 Id. 266 Id. 261 Id. 268 Staff Ex. 6 (Cutter Direct) at 21-24. 269 Id. at 24. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE92 PUC DOCKET NO. 39896 sensitive to Federal Reserve System policy. By using the difference between the averages of the yield of long-term government bonds and the yield of large company stocks between 1926and2010, the effect of Federal Reserve System policy on the risk premium was significantly diluted. Mr. Cutter found that because the CAPM estimate of ETI' s cost of equity was excessively low, even with adjustments for Federal Reserve System policy, it would be appropriate to further adjust it by multiplying the unadjusted estimate plus two times the effect of adjusting the risk-free rate, or: 6.93 percent+ (2 * 0.99 percent)= 8.91 percent. 270 It is important to note, however, that Mr. Cutter used the CAPM analysis only as a qualitative check on its DCF and risk premium analyses, not as an independent source of analysis. Although Cities witness Parcell did perform a CAPM analysis, he does not employ the CAPM results in arriving at his 9.0 percent to 10.0 percent range of results. 271 State Agencies witness Miravete used the daily average of the yield of the ten-year Treasury bond between December 1, 2011, and March 2, 2012, as reported by the Board of Governors of the Federal Reserve System, as his risk-free return in his CAPM model. He used Value Line's most recent betas for the regulated utilities included in the proxy group. Dr. Miravete corrected the betas by substituting an average between their value and LO to recognize that markets trend towards long-term equilibrium because these regulated utilities were able to attract investors during the most troubled times, which indicates that the perceived market risk of these utilities is lower than for other firms. Dr. Miravete's capitalization-weighted average CAPM ROE is 7.64 percent on a 90 days averaging period, with a range between 7.64 percent (30 days) and 8.28 percent (180 days). Dr. Miravete characterizes these estimates as low relative to those of the DCF model because of the low yields of Treasury bonds after the implementation of the quantitative easing monetary policy over the past two years. 272 270 Id. at 21, 24-25. 271 Cities Ex. 3 (Parcell Direct) at 3, 25-28. 272 State Agencies Ex. 1 (Miravete Direct) at 19-21. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE93 PUC DOCKET NO. 39896 6. ALJs' Analysis Given the detail, time, and effort that went into the various experts' testimony on this issue, one might easily conclude that the development of an estimated ROE is a precise science. But, as acknowledged by virtually all experts on the subject, estimating the cost of equity is not an exact science but rather a result of informed judgment. The first question that must be addressed is the appropriate proxy group. There were essentially only two competing views on this issue- one presented by Dr. Hadaway and the other by Mr. Cutter. The ALJs have reviewed the evidence and the arguments of both sides with respect to the composition of the proxy group. Although Staff's proxy group could, in some respects, be considered more comparable to ETI than Dr. Hadaway' s larger group, the Al.J s do not believe that this overcomes the flaws inherent in such a small group. In the end, a group of nine companies, while comparable, simply does not provide a robust enough sample to create a valid group for comparison. The Al.J s therefore find that the 23 utility group selected by ETI witness Hadaway is the appropriate proxy group. The next issue is the core issue to be decided: the appropriate ROE for ETI. The experts in this case testified to the following ROE ranges or estimates, depending on the calculation methodology employed: Witness/Analvsis Ranee Ultimate Recommendation Hadaway - DCF 9.9 10.7 10.6 Hadaway - Risk Premium 9.96 10.38 - Cutter-DCF 7.46-10.71 9.6 Cutter - Risk Premium 9.81 Cutter - CAPM 8.91 Gorman-DCF 9.3-9.7 9.5 Gorman Risk Premium 9.2-9.4 Parcell - DCF 9.0 9.5 9.5 Parcell - Comparable Earnings 9.5-10.0 SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE94 PUC DOCKET NO. 39896 Witness/Analysis Ranee Ultimate Recommendation Szerszen - DCF 8.32 9.32 9.3 Szerszen - Risk Premium 9.3 Miravete - DCF 9.23-9.34 9.3 Miravete CAPM 7.64- 8.28 Just focusing on the ultimate ROE recommendations, it is clear that there is a fairly tightly grouped range when considering Staff and the intervenors. This ranges from a low of 9 .3 percent to a high of 9 .6 percent. The range expands when it is considered that Staff witness Cutter did not contest ETI' s assertion that Staffs DCF recommended ROE would be 10.0 percent if he had used the same proxy group as the other witnesses. 273 The ALls believe that the criticisms leveled at Dr. Hadaway's ROE recommendation are generally correct, certainly to the point that the ultimate recommendation is so high as to be an outlier. The ALJ s conclude that the proper range of acceptable ROEs would be from 9.3 percent to 10.0 percent. This is actually confirmed by ETI's own witness, Mr. Barrileaux, who testified that, from a cash flow metric standpoint, an ROE of 9.99 percent would provide "a reasonable outcome that balances debt and equity financing." 274 The mid-point of the range discussed above is 9.65 percent. There has been a tremendous amount of testimony about the unsettled economic conditions facing utilities and the effect of those conditions on the appropriate ROE. The ALJs believe that this is an effect that must be taken into, account, and that the effect would be to move the ultimate ROE towards the upper limits of the range determined to be reasonable. In this case, the ALJ s find that the reasonable adjustment would be 15 basis points, moving the reasonable ROE to 9.80 percent. Accordingly, the ALls recommend that the Commission find that 9.80 percent is the appropriate ROE for ETI. 273 Tr. at 1795. 274 ETI Ex. 44 (Barrileaux Rebuttal) at 5, Ex. CEB-R- L SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE95 PUC DOCKET NO. 39896 C. Cost of Debt ETI' s weighted average cost of debt at the end of the test year was 6. 74 percent. 275 No party has taken issue with that cost of debt. Therefore, the ALl s recommend that the Commission enter an order finding that the appropriate cost of debt for ETI is 6.74 percent. D. Overall Rate of Return The overall rate of return is a product of the capital structure, ROE, and cost of debt. Based on the discussions set forth above, the ALls recommend that the Commission adopt the following overall rate of return for ETI: Weighted Component Cost Weif!htin2 Cost Debt 6.74 50.08% 3.38 Equity 9.80 49.92% 4.89 Overall 8.27 VII. OPERATING EXPENSES [Germane to Preliminary Order Issue Nos. 2, 3, 4, and 16] A. Purchased Power Capacity Expense [Germane to Supplemental Preliminary Order Issue No.1] One of the most hotly contested issues in this case concerned the appropriate size of ETI' s purchased power capacity costs (PPCCs). In order to understand this issue, it is necessary to understand some background relative to how ETI obtains and uses power generation capacity. 1. The Sources of ETI's Purchased Power The Entergy System Agreement is a FERC-approved tariff that mandates that the Operating Companies operate as a single, integrated system. 276 The System Agreement's essential function is to provide the contractual basis for the planning, construction, and operation of generation and 275 ETI Ex. 5 (Barrilleaux Direct) at 37. 276 ETI Ex. 30 (Jaycox Direct) at 5-6; ETI Ex. 39 (Cicio Direct) at 6-10. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE96 PUC DOCKET NO. 39896 transmission resources in an economic and reliable manner. By jointly planning and operating their electric systems, the Operating Companies believe they are able to aggregate their loads and jointly dispatch their resources to serve that load using the lowest cost resources available from all of the Operating Companies, resulting in lower total costs than the total cost of each Operating Company planning and operating separately. Another function of the Entergy System Agreement is to provide a basis for the equalization among the Operating Companies of any imbalances of costs arising from the construction, ownership, or operation of facilities that are used for the collective benefit of all Entergy Operating Companies. 277 To provide reliable service, ETI must have sufficient generation capacity to meet the maximum demands imposed on its system. Some of this generation capacity (approximately 1,200 MW) is generating plants owned and operated by ETI. 278 The remainder of ETI' s capacity comes from four types of purchased capacity: (1) capacity purchases from third parties; (2) capacity purchases from other Entergy affiliates through "legacy affiliate contracts" under MSS-4; (3) capacity purchases from other Entergy affiliates through "other affiliate contracts" under MSS-4; and (4) capacity purchases from the Entergy system through reserve equalization payments under MSS-1. 279 MSS-1 and MSS-4 are schedules included in the Entergy System Agreement which set out complex mathematical formulas whereby the various Operating Companies can equalize and share the costs of power capacity among themselves. 280 These four sources of purchased capacity are inversely related to one another: the more ETI purchases from one source, the less it needs to purchase from the others. 281 ~ Capacity Purchases from Third Parties Third-party capacity contracts are contracts that the system has allocated in whole or part to ETI. ETI has contracted to purchase capacity from a number of third parties, including 277 ETI Ex. 39 (Cicio Direct) at 6, 8-10, 11-30. 278 Tr. at 1539-40. 279 ETI Ex. 34 (Cooper Direct) at 20-21; Tr. at 1901; ETI Initial Brief at 71. 280 ETI Ex. 39 (Cicio Direct) at PJC-1, pp. 30 and 62. 281 Tr. at 1946-47. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE97 PUC DOCKET NO. 39896 ConocoPhillips-SRW, Dow Pipeline, Frontier, Calpine-Carville, and Sam Rayburn Municipal Power Agency (SRMPA). Since 2009, ETI has been in the process of substantially increasing its reliance upon third party purchases of capacity. During the Rate Year, it plans to more than double the amount of capacity it purchases from third parties as compared to the amount it purchased during the 282 Test Year. Since the Test Year, Entergy has been engaged in an effort to increase ETI's long-term power capacity through dealing with third parties. It has entered into a number of agreements in that regard: • In 2009, it entered into a ten-year purchased power agreement with Calpine Energy Services (Calpine) to purchase 485 MW of capacity from Calpine's Carville Energy Center (Carville Contract). Purchases pursuant to the Carville Contract will commence during the Rate Year, on June 1, 2012, and 50 percent of this contract is allocated to ETI. 283 • During the Period from July 2009 through June 2011, the Company executed an agreement with NRG for a 75 MW one-year call option, with a delivery period that began on March 1, 2011, and 100 percent of this contract is allocated to ETI. 284 • During the Period from July 2009 through June 2011, the Company executed a three-year agreement with Dow Pipeline for 100 MW capacity, with a delivery period that began on April 1, 2011, and 100 percent of this contract is allocated to ETI. 285 • During the Period from July 2009 through June 2011, the Company executed a 25-year agreement with SRMPA for 225 MW, with a delivery period beginning on December 1, 2011, and 100 percent of this contract is allocated to ETI. ETI contends that the SRMPA contract will be beneficial because it provides "much-needed long-term base load capacity at an economically attractive price."286 282 ETI Ex. 34 (Cooper Direct) at 23; see also ETI Init. Br. at 75-76. 283 ETI Ex. 34 (Cooper Direct) at 16, 19. 284 ETI Ex. 34 (Cooper Direct) at 16, 19. 285 Id. at 17, 19. 2s6 Id.  ····---··---- SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE98 PUC DOCKET NO. 39896 • An additional contract, the Frontier contract, was in place during the Test Year, and saw a 150 MW increase in contract capacity during the Test Year. 287 ETI argues that its growing reliance on third-party purchases will diversify its energy portfolio and help the Company meet its reliability needs at a lower cost. 288 The new purchased power contracts will also reduce ETI's fuel costs and dependence upon aging, higher heat rate generation units within the Entergy system. 289 » Capacity Purchases from Other Entergy Affiliates Through "Legacy" Affiliate Contracts Under MSS-4 The term "legacy affiliate contracts" refers to those contracts resulting from the December 31, 2007, jurisdictional separation of EGSI into ETI and EGSL, pursuant to which ETI purchases its allocated share of power from plants such as the River Bend nuclear plant, located in Louisiana and owned by EGSL as a result of the separation. The legacy affiliate purchases are made under MSS-4. 290 » Capacity Purchases from Other Entergy Affiliates Through "Other" Affiliate Contracts Under MSS-4 "Other affiliate contracts" refers to all affiliate contracts other than legacy contracts whereby ETI purchases capacity and associated energy from other Operating Companies. 291 The other affiliate purchases are also made under MSS-4. 292 Among others, in 2009 ETI entered into a new affiliate contract with Entergy Arkansas, Inc. (EAI) for wholesale base load resources (the EA WBL Contract), whereby ETI was allocated 31. 7 percent of 336 MW capacity. 293 287 Tr. 1937-38. 288 ETI Ex. 34 (Cooper Direct) at 24. 289 Tr. at 1112-13, 1940-41. 290 ETI Ex. 39 (Cicio Direct) at 24-26. 291 ETI Ex. 34 (Cooper Direct) at 21. 292 ETI Ex. 39 (Cicio Direct) at 24-26. 293 Cities Ex. 6 (Nalepa Direct) at 13-14.  ..~-·----- SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE99 PUC DOCKET NO. 39896 ~ Capacity Purchases from the Entergy System Through Reserve EqualizaJion Payments Under MSS-1 Reserve Equalization payments are made under MSS-1. In any given month, some of the Operating Companies might be "long" on the amount of generating capacity they own (meaning that they own more capacity than they need) while others might be "short" on capacity (meaning they own less capacity than they need). In such a month, the long Operating Companies would receive 294 MSS-1 payments from the short Operating Companies for use of their capacity. 2. ETl's Request Regarding PPCCs During the Test Year, ETI had total PPCCs of $245,432,884. 295 In the application, however, ETI is not seeking to recover its Test Year expenses. Rather, it is asking to recover roughly $276 million, which represents the Company's anticipated PPCCs in the Rate Year. 296 In other words, ETI is seeking roughly $31 million more than its actual Test Year expenses. ETI derived this estimate based largely upon what it believes will the purchased power agreements in place during the Rate Year. 297 As the following tables illustrate, ETI projects that, during the Rate Year, the total quantity, and the relative quantities purchased from each source, will differ substantially from its Test Year purchases. Test Year vs. Rate Year Power Capacity Quantities (MW-Months)298 Purchase Test Year Rate Year Third Party Purchases 5,884 12,834 294 ETI Ex. 39 (Cicio Direct) at 11-13; Cities Ex. 4 (Goins Direct) at 13. 295 TIEC Ex. 1 (Pollack Direct) at Ex. JP-1; Tr. at 652-53. 296 TIEC Ex. 1 (Pollack Direct) at JP-1; ETI Ex. 34 (Cooper Direct) at 20; ETI Ex. 34A (Errata to Cooper Direct). 297 TIEC Ex. l (Pollack Direct) at 22. 298 TIEC Ex. 1 (Pollack Direct) at 22, Table 1 (Errata). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 100 PUC DOCKET NO. 39896 Test Year vs. Rate Year Power Capacity Quantities (MW-Months)298 Purchase Test Year Rate Year Affiliate Purchases (both 21,670 21,711 Legacy and Other) Under MSS-4 Reserve Equalization 8,309 5,262 UnderMSS-1 Total 35,863 39,807 Test Year vs. Rate Year Power Capacit v Costs2"" Purchase Test Year Rate Year Third Party Purchases $32,094,893 $69 ,061,200 Affiliate Purchases (both $189,032,442 $188,430,917 Legacy and Other) Under MSS-4 Reserve Equalization $25,461,353 $18,317,367 UnderMSS-1 Total $246,588,688j!JU $275,809,484 This indicates ETI will purchase roughly 11 percent more power in the Rate Year than it did in the Test Year. Moreover, while the purchases pursuant to MSS-4 will remain fairly stable, the third-party purchases will substantially increase, with a somewhat corresponding decrease for purchases pursuant to MSS-1. In other word, ETI' s plan is to become "less short" (on capacity) relative to the other Operating Companies in the Rate Year than it was in the Test Year. ETI contends that the shift toward more third party purchases is part of its effort to develop a more diverse, modern, and efficient portfolio of generation supply resources, both to serve current customer needs and to serve anticipated load growth. This, in turn, will lower energy costs and result in savings for customers. 301 299 Cities Ex. 12. 300 Cities now agree that the correct amount for the Test Year is $245,432,884. See TIBC Reply Brief at 18. 3 ot ETI Ex. 47 (Cooper Rebuttal) at 7-8. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 101 PUC DOCKET NO. 39896 ETI' s initial request in this case was for a Purchased Power Rider (PPR) that would allow the Company to recover $276 million, but would be subject to future reconciliation based on actual expenses and revenues, much like a fuel factor. 302 The intervenors point out that the PPR proposal, while unprecedented, would have at least matched any post-Test Year increases in total purchased capacity costs with corresponding increases in sales, and would also have allowed for a prudence review of any post-Test Year purchased power capacity expenses in a future reconciliation proceeding. 303 The Commission, however, rejected the PPR proposal in its Supplemental Preliminary Order. 304 In lieu of the PPR proposal, ETI now proposes to simply recover the $276 million as part of its base rates. 3. Staff and Intervenors' Opposition to ETl's PPCCs Proposal Staff and all of the active! y-engaged intervenors oppose ETI' s proposed adjustment to its Test Year PPCCs. They make a number of arguments against ETI' s proposal. (a) The PPCCs Requested by ETI Are Not Known and Measurable First, they contend that ETI' s Rate Year forecast cannot be considered known or measurable. Staff points out that the four3° 5 components from which ETI purchases power are interrelated, such that, "when ETI adds capacity under one element, such as through third party contracts, the other components, such as ETI's MSS-1 payments, will decrease."306 Staff describes each of the components comprising ETI' s PPCC Rate Year forecast as being "infected" with numerous assumptions. 307 For example, ETI necessarily made projections, rather than relying upon actual payments, when it estimated what it will pay for third-party contracts in the Rate Year. 308 Many of 302 Tr. at 1954; Cities Ex. 4 (Goins Direct) at 14. 303 TIEC Init. Br. at 25-26; Tr. at 1954; Cities !nit. Br. at 37; Cities Ex. 6 (Nalepa Direct) at 8. 304 Supplemental Preliminary Order at 2 (Jan. 9, 2012). 305 Staff (and some of the intervenors) describe them as three components, by combining affiliate purchases under legacy contracts and affiliate purchases under other contracts into one component. 306 Staff Initial Brief at 25 (citing Tr. at 1946). 307 Staff Initial Brief at 26. 308 Tr. at 704. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 102 PUC DOCKET NO. 39896 the third party contracts that will be in effect in the Rate Year do not contain fixed price terms. Rather, the amounts ETI will pay will fluctuate based upon factors such as required availability and performance. Nevertheless, ETI simply assumed it would pay the maximum amount possible under each of its third party contracts, and disregarded any of the contractual factors that might reduce its Rate Year payments. 309 Thus, the intervenors contend that ETI's cost estimates for third party purchased power are merely projections, as opposed to known and measurable changes. 310 Similarly, ETI' s contractual agreements with its affiliate Operating Companies require ETI to make assumptions about their future costs. The contracts do not definitively fix prices or quantities. Rather, prices and quantities under the contracts will fluctuate based on the specific operational conditions actually experienced by the various Operating Companies during the Rate Year. 311 The ultimate determination of payments made in the Rate Year will be calculated based upon the complex mathematical formula set out in schedule MSS-4. That formula contains a great number of variables. ETI had to make assumptions about each one of those variables in order to estimate its Rate Year costs. 312 The intervenors point to ETI' s new contract with EAi (the EA WBL Contract) as evidence of the "inherently speculative nature" of ETI' s PPCCs request. According to the intervenors: • the EA WBL Contract was signed on April 11, 2012 (only days before the hearing in this matter commenced); purchases will not commence under the contract until January 1, 2013; • pricing under the contract will be determined in 2013 pursuant to the complex formula contained inMSS-4; • the quantity of capacity ETI ultimately purchases under the contract will be based on a yet-to-be- determined allocation percentage between ETI and the other Operating Companies; • the contract itself may never go into effect because it is contingent upon ETI receiving all necessary "regulatory approvals" before August 1, 2012; and 309 Tr. at 704-05. 310 TIEC Initial Brief at 29-30; Staff Initial Brief at 26. 311 Tr. at 606. 312 See Staff Initial Brief at 27; Tr. 606. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE103 PUC DOCKET NO. 39896 • if it does go into effect, it will still be subject to at least two further revisions before any power is received by ETI under the contract. 313 The EA WBL Contract accounts for more than one-third of ETI' s upward adjustment to its Test Year PPCCs. The intervenors contend that, in order for ETI to arrive at its forecasted PPCCs for the Rate Year, it had to make myriad assumptions as to the future values of the many variables in the EA WBL Contract (and the other affiliate contracts). 314 Therefore, the intervenors argue that ETI' s cost estimates for its contractual agreements with its affiliate Operating Companies are merely projections, as opposed to known and measurable changes. 315 ETI' s estimated costs for its MSS-1 payments also require assumptions about the future. In order to calculate its future reserve equalization responsibilities using the complex formula set out in MSS-1, ETI had to forecast its own future loads, along with the future loads of all the other Operating Companies. If those assumptions prove to be wrong, then ETI' s actual MSS-1 costs will be different than as projected in the application. 316 It is noteworthy, according to the intervenors, that ETI projected the future load growths of all the Operating Companies when it calculated its projected Rate Year MSS-1 costs because, elsewhere in ETI' s evidence, the Company has taken the position that future projected loads should not be considered known and measurable. 317 Staff argues: ETI cannot have it both ways. It cannot claim load growth to be speculative in one context, and then claim that it can forecast with absolute certainty the respective load growths for each EOC on the Entergy System. 318 TIEC points out that ETI' s estimated MSS-1 payments "were still changing on the eve of the hearing."319 In the following exchange, even ETI witness Phillip May, one of the Company's 313 ETI Ex. 47 (Cooper Rebuttal) at RRC-R-1, and Tr. at 628-9. 314 Staff Initial Brief at 27-28. Staff makes the further point that, because the EA WBL Contract was executed only days before the hearing, Staff has been unable to determine whether the contract is even a prudent one. 315 TIEC Initial Brief at 30-32; Staff Initial Brief at 27-28. 316 Tr. at 651-52. 317 Tr. at 1907; see also Staff Initial Brief at 28; TIEC Initial Brief at 27-28. 318 Staff Initial Brief at 29; see also TIEC Initial Brief at 37. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 104 PUC DOCKET NO. 39896 primary witnesses regarding its PPCCs, seems to have conceded that the Company's MSS-1 projections are not known and measurable: Q: Do you think that the projection ... of rate year sales that is implicit in the calculation of MSS-1 costs ... is a known and measurable change? A: I think that there is some uncertainty with regard to that projection, yes, sir. 320 In sum, the intervenors contend that ETI' s cost estimates for all components of purchased power in the Rate Year are merely projections, as opposed to known and measurable changes. 321 (b) The PPCCs Requested by ETI Violate the Matching Principle Second, the intervenors acknowledge the principle that Test Year expenses may be adjusted for known and measurable changes. However, they contend that such adjustments can only be made where the attendant impacts on all aspects of a utility's operations (including revenue, expenses, and invested capital) can with reasonable certainty be identified, quantified, and matched.322 They assert that ETI' s proposed adjustment does not satisfy this matching principle. The intervenors complain that ETI is improperly attempting to "compare apples to oranges" by mixing a forecast of future Rate Year PPCCs with actual Test Year billing determinants. As explained by Cities witness Nalepa, "[u]nder the company's approach of mixing estimated rate year costs with test year billing units, there is a failure to recognize customer growth and increased sales revenue - thus overstating the revenue requirement."323 The argument, essentially, is that the various new or expanded contracts that ETI has entered into were executed so that, in whole or in part, ETI would be able to meet future demand, but that ETI is seeking to recover the costs of those new contracts from its existing customers. 324 319 TIEC Initial Brief at 28. 320 Tr. at 1918-19. 321 TIEC Initial Brief at 27-28; Staff Initial Brief at 29. 322 Cities Ex. 6 (Nalepa Direct) at 12, citing P.U.C. SUBST. R. 25.23 l(c)(2)(F). 323 Cities Ex. 6 (Nalepa Direct) at 8; Cities Ex. 4 (Goins Direct) at 14-15. 324 Cities Ex. 6 (Nalepa Direct) at 11; see also Cities Initial Brief at 38, Staff's Initial Brief at 30, TIEC Initial SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 105 PUC DOCKET NO. 39896 The intervenors offer various examples, of which the following is typical, to illustrate why it was inappropriate for ETI to fail to take load growth into account when it calculated its Rate Year PPCCs. Assume that, during the Test Year, Utility X had 100 billing units and $500 of PPCCs. Also assume that, during the Rate Year, Utility X had 200 billing units and $1,000 of PPCCs. If Utility X were limited to setting its rates based solely on its Test Year numbers, then it would recover precisely the right amount to cover its PPCCs in both the Test Year (100 billing units x $5 per unit= $500 of PPCCs) and in the Rate Year(200 billing units x $5 per unit= $1,000 of PPCCs). If, on the other hand, Utility X were allowed to set its rates based upon it billing units from the Test Year(lOO) and its PPCCs from the Rate Year ($1,000), then Utility X would unfairly recover twice the amount needed to cover its actual PPCCs in the Rate Year (200 billing units x $10 per unit= $2,000). 325 Thus, intervenors contend that ETI' s load growth must be taken into account if PPCCs are to be based on Rate Year projections. 326 They point out that ETI itself expects steady load growth in the next few years, 327 and experienced "good" growth over the two years preceding the Test Year. 328 For its part, ETI denies that its increased capacity has been obtained in order to meet load growth. Rather, it contends that it has added capacity in order to be "less short" in comparison to the other Operating Companies. 329 Moreover, ETI contends that the load growth adjustments proposed by intervenors are "uncertain and unnecessary." 330 (c) ETl's Proposal Would Preclude Prudence Review Third, TIEC contends that ETI' s future Rate Year proposal would set rates based on projections without any effective Commission review of: (1) what the actual expenditures under Brief at 35-39. 325 Cities Ex. 4 (Goins Direct) at 16-17. 326 Cities Ex. 4 (Goins Direct) at 17; see also TIEC Ex. 23. 327 Cities Ex. 4 (Goins Direct) at 17; Tr. at 706. 328 Tr. at 130. 329 ETI Initial Brief at 68-69. 330 Id. at 69. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE106 PUC DOCKET NO. 39896 purchased capacity contracts turn out to be; (2) whether those expenditures turn out to be reasonable; and (3) whether the future contracts were prudent. 331 4. The Intervenors' Recommendations Regarding PPCCs The intervenors agree that the amount requested by ETI is unreasonable, excessive, and should be rejected. They do not universally agree, however, about what the proper number for PPCCs should be. Staff, TIEC, and State Agencies argue that ETI' s PPCCs should be set at the amount of the Company's Test Year PPCCs: $245.4 million. This position is best summarized by Staff: Staff recommends that the Commission adhere to traditional ratemaking principles and set the amount of ETI' s purchased power expenses based on what the Company actually experienced during its test year. During its test year, ETI had total purchased power capacity expenses of $245.4 million. This amount is not in dispute. This amount is known. This amount is measurable. The Commission should utilize this amount to set just and reasonable rates for ETI and its ratepayers. 332 Rather than recommending Test Year PPCCs, Cities offer two alternatives - one recommended by its witness Dr. Dennis Goins, and another recommended by its witness Mr. Nalepa. 333 Dr. Goins recommends that ETI be allowed to recover PPCCs of roughly $242.9 million. 334 This amount is roughly $33 million less than ETI's requested amount and $3 million less than ETI' s actual Test Year costs. To arrive at this amount, Dr. Goins made several calculations. First, he adjusted the average perkW cost of ETI' s legacy and other affiliate purchases using cost data from November 2010 through October 2011, which is slightly more current data than that relied upon by ETI. 335 Second, as to MSS-4 costs, because the EA WBL contract is set to expire sooner than the three years he assumed ETI' s new rates will be in effect, Dr. Goins "normalized" the 331 TIEC Initial Brief at 33-35. 332 Staff Initial Brief at 29. 333 Cities Initial Brief at 40. 334 Cities Ex. 6 (Nalepa Direct) at 17, and Errata No. 3. 335 Cities Ex. 4 (Goins Direct) at 17-18. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE107 PUC DOCKET NO. 39896 costs of the EA WBL contract over the three year period. 336 Finally, he adjusted the Rate Year total PPCCs estimate to reflect the effects of load growth, based upon ETI forecasts. 337 Mr. Nalepa took a slightly different approach. He recommended that ETI be allowed to recover PPCCs of $236,838,634, or roughly $39 million less than ETI' s requested amount and $8 million less than ETI's Test Year costs. 338 To arrive at this amount, Mr. Nalepa first calculated the per kW cost of ETI's third party Rate Year capacity and applied it to ETI's Test Year-end capacity. In this way, "the increased cost of the new resources is recognized, but current demand is better matched to current resources."339 Second, he made the same adjustment as Dr. Goins as to MSS-4 costs due to the EA WBL contract. 340 TIEC explains it is reluctant to "descend into the rabbit hole and engage in ratemaking based on prognostications, estimates, projections, and assumptions about what may happen in the future." 341 If the Commission were to do so, however, TIEC argues that the final result would be lower than the Test Year PPCCs, not higher. TIEC' s witness Jeffry Pollock calculated the impact of projected unit prices based upon ETI' s projections, and he eliminated the expiring EA WBL Contract. His result, which TIEC is not advocating, would allow ETI to recover PPCCs of $238.8 million, roughly $7 million less than its Test Year costs. 342 ETI describes the proposals made by TIEC and Cities as "extreme" and contrary to common sense. 343 For example, Mr. Pollock's calculations indicate that ETI' s MSS-1 costs would increase by roughly $5 million, while its third-party and affiliate contracts would slightly decrease. ETI argues 336 Cities Ex. 4 (Goins Direct) at 18; Cities Ex. 6 (Nalepa Direct) at 15-16. 337 Cities Ex. 4 (Goins Direct) at 18- l 9. 338 Cities Ex. 6 (Nalepa Direct) at 17. 339 Cities Ex. 6 (Nalepa Direct) at 12-13. 3 4-0 Id. at 15-16. 341 TIEC Initial Brief at 41. 342 TIEC Ex. 1 (Pollack Direct) at 25-27; TIEC Initial Brief at 41-42. 343 ETI Initial Brief at 83. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 108 PUC DOCKET NO. 39896 that this is the opposite of reality. By adding capacity through third party contracts, its reliance upon the other purchased power components, especially MSS-1, will necessarily decline, not increase. 344 ETI also argues that load growth is inherently uncertain and should not be taken into account. 345 5. The ALJs' Analysis Regarding PPCCs The AU s conclude that ETI failed to meet its burden to prove that the adjustment it seeks to its Test Year PPCCs is known and measurable. The known and measurable standard is an exception to the actual data contained in the Test Year. The point of a historical Test Year is to review actual costs, which include the ups and downs of what actually occurred. As to a forecast of the Rate Year, by contrast, the evidence demonstrates that the costs attributable to a particular contract to purchase capacity cannot currently be known because there are so many variables that will play into the amount ETI ultimately pays. As stated above, ETI' s third party contracts lack fixed prices and the amounts ETI will pay could fluctuate based upon factors such as required availability and performance. ETI simply assumed it would pay the maximum amounts under those contracts, and disregarded the contractual factors that could lower the payment amounts. Yet this assumption runs counter to ETI' s historical experience with its contracts. 346 Similarly, ETI' s affiliate contracts do not fix prices or quantities, and the amount ETI ultimately pays will fluctuate based upon operational conditions experienced by all of the Operating Companies during the Rate Year. Those operational conditions obviously cannot be known at this time. Both the affiliate contracts under MSS-4 and the equalization payments under MSS-1 are based upon highly complex mathematical formulae that utilize numerous variables. Any of the variables could change during the Rate Year, thereby altering the amounts paid by ETI under affiliate contracts or MSS-1. As a result, the evidence demonstrates that there could be a substantial difference between ETI' s projected Rate Year costs and what 344 Id. 83. 345 Id. 84. 346 Tr. at 705. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 109 PUC DOCKET NO. 39896 actually ends up occurring. ETI asks the Commission to trust it that these differences would be "small,"347 but provides no evidence as to what small means. The efforts made by ETI, Cities, and TIEC to forecast Rate Year PPCCs further illustrate the difficulty of deviating from actual Test Year data in an area that involves so many future contingencies and unknowns. Those forecasts swung wildly- ETI estimated Rate Year PPCCs that were $31 million more than the Test Year, while the Cities' and TIEC's estimates came in at $3 million, $8 million, and $7 million less than the Test Year, respectively. Indeed, even Cities' own witnesses disagreed substantially among themselves as to what the proper amount should be. Moreover, arguably ETI could not even agree with itself regarding the proper amount because, in its Initial Brief, it suggested that a reduction of roughly $4.5 million might be warranted to account for its latest projection of its MSS-1 costs in the Rate Year. 348 The ALls are similarly convinced that ETI's request violated the matching principle by mixing its forecast of future Rate Year PPCCs with Test Year billing determinants. It is logically inconsistent for ETI to have, on the one hand, based its estimate of Rate Year MSS-1 costs on its projections of the load growths of ETI and all the other Operating Companies and, on the other hand, argue that load growth cannot be considered known and measurable when calculating its overall PPCCs. This argument does not withstand scrutiny, especially in light of tJ:ie fact that ETI clearly believes its load will be larger in the Rate Year than it was in the Test Year and it has, in fact, contracted for six percent more load in the Rate Year. 349 Simply put, the intervenors presented substantial evidence that all of the components of ETI' s purchased power capacity contain significant variability and uncertainty in costs, thereby leading to the conclusion that estimates of Rate Year PPCCs cannot be considered known and measurable. For this reason, the ALls recommend that ETI's PPCCs request be rejected. In its place, the ALls recommend that ETI be allowed to recover its Test Year PPCCs of $245,432,884. 347 ETIInitial Brief at 81. 348 ETI Initial Brief at 77 (citing Tr. at 684, 1945). 349 ETI Ex. 47 (Cooper Rebuttal) at 4; Tr. at 667-68. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 110 PUC DOCKET NO. 39896 B. Transmission Equalization (MSS-2) Expense The Entergy system transmission grid is a large, integrated transmission network that is operated for the mutual benefit of all of the Entergy Operating Companies. 350 Service Schedule MSS-2 is a FERC jurisdictional tariff that equalizes the ownership costs of certain high voltage transmission facilities among ETI and the other Operating Companies, so that each Operating Company pays its just and reasonable share of those costs. Accordingly, those costs are referred to as "transmission equalization" payments. 351 MSS-2 generally applies to equalization of transmission costs for transmission assets of 230 kV and larger. 352 In any given month, some of the Operating Companies might be "long" on the amount of transmission capacity they own (meaning that they own more capacity than they need) while others might be "short" on capacity (meaning they own less capacity than they need). In such a month, the long Operating Companies would receive MSS-2 payments from the short Operating Companies for use of their transmission facilities. 353 Over the course of the Test Year, ETI was short, meaning that it paid a total of $1,753,797 in MSS-2 payments to various other Operating Companies. 354 In the application, rather than seeking to recover only the $1.7 million in Test Year MSS-2 costs, ETI is seeking to recover roughly $10.7 million, which represents its anticipated MSS-2 expenses in the Rate Year. 355 The additional $9 million that ETI seeks is based on the Company's estimates of transmission construction projects that are expected to have been completed by or during the Rate Year which will result in changes to the relative transmission line ownership ratios between the Operating Companies. In other words, ETI expects that, by or during the Rate Year, its ownership share under the MSS-2 will decrease relative to the other Operating Companies (as the 350 Tr. at 450, 793. 351 Tr. at 724; ETI Ex. 39 (Cicio Direct) at 15-17 and PJC-1at38. 352 Tr. at 450-51, 73 l. 353 Tr. at 731, 735. 354 Tr. at 723-24, 737; Cities Ex. 28. 355 Tr. at 452-53, 738, 760. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE Ill PUC DOCKET NO. 39896 transmission capacity owned by the other Operating Companies increases), thereby driving the amount of ETI's MSS-2 payments upward. 356 The increase is driven by ETI's prediction that $184.9 million in additional transmission capacity will be built by other Operating Companies by the end of the Rate Year. ETI identified six construction projects that are either underway or approved for construction and which, collectively, will account for roughly $141 million of the predicted $184.9 million in additional transmission capacity. Of those six projects, one was completed and went into service on December 16, 2011, after the end of the Test Year. The other five are either under construction or still in the planning phase and are currently scheduled to go into service on dates ranging from June 29, 2012, to December 31, 2012. 357 According to ETI, the remaining $43.9 million of the $184.9 million in additional transmission capacity is derived from "an estimate of the capital investment necessary to maintain equalizable [i.e. MSS-2 qualifying] transmission investments across the Entergy Transmission System."358 The estimate is based upon the Operating Company's projected budgets and historical spending patterns for maintenance of transmission facilities. 359 Staff, State Agencies, TIEC, and Cities all oppose ETI's effort to recover $10.7 million in MSS-2 expenses. The parties make a number of arguments. First, they point out that MSS-2 utilizes a complex mathematical formula to calculate each Operating Company's liability (or credit) under the equalization process. There are a great number of variables that are used in the formula, such as the amount of investments made by each Operating Company in transmission facilities, the costs of capital for each Operating Company, the size of the load demanded by each Operating Company, and the amount of state and federal taxes paid by each Operating Company. Changes to any of these variables can change the amount ETI owes (or is due) pursuant to MSS-2. 360 Moreover, these variables relate not only to ETI, but to all of the Operating Companies. Indeed, Cities calculate that, 356 Tr. at 775-77. 357 ETI Ex. 59 (McCulla Rebuttal) at 2 and MFM-R-1; Tr. at 456-58. 358 ETI Ex. 59 (McCulla Rebuttal) at 3. 359 Id. 360 ETI Ex. 39 (Cicio Direct) at PJC-1 at 38-43; Tr. at 454-55. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 112 PUC DOCKET NO. 39896 to perform the MSS-2 calculation, at least 360 "mini-forecasts" must be made, only 60 of which relate to ETI. 361 As explained by TIEC witness Pollock, any effort to estimate future amounts of these many variables "is susceptible to a host of uncertainties." 362 The intervenors argue that for ETI to arrive at its estimate of$10.7 inMSS-2 costs duringthe Rate Year, the Company had to speculate as to what the many MSS-2 variables would be in the Rate Year. In other words, they contend that ETI's estimate of its future MSS-2 costs cannot possibly be considered "known and measurable" and, therefore, is not recoverable. 363 State Agencies and Staff liken ETI's attempt to obtain an MSS-2 adjustment for not-yet-complete construction projects to an impermissible request to recover the costs of CWIP without having to meet PURA's burden of proving that recovery is necessary to protect the utilities financial integrity. 364 Second, the parties oppose ETI's effort to recover its predicted MSS-2 expense in the Rate Year point out that the primary driver of the increased costs over the Test Year comes from a number of transmission projects that have not yet come into service, and are still in the planning or construction phase. ETI concedes that if the projects do not actually come into service at the currently estimated times, then the Company's estimates of its MSS-2 costs during the Rate Year will be inaccurate. 365 Thus, Staff contends that ETI's projections about future MSS-2 costs cannot be considered known and measurable. 366 Moreover, TIEC and Staff contend that ETI is effectively seeking higher rates based upon expenses associated with projects that are not yet completed and, therefore, the projects cannot be considered ''used and useful."367 As explained by TIEC: 361 Cities Reply Br. at 68-69. 362 TIEC Ex. 1 (Pollock Direct) at 29. 363 Staff Initial Brief at 31; State Agencies Initial Brief at 11-13; TIEC Initial Brief at 44-45; Cities Initial Brief at44. 364 State Agencies Initial Briefat 12 (citing PURA§ 36.054; P.U.C. SUBST. R. 25.23 l(c)(2)(D)); Staff Reply Brief at 20. 365 Tr. at 800-801 366 Staff Initial Brief at 32. 367 TIEC Initial Brief at 47; Staff Initial Brief at 19-20. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 113 PUC DOCKET NO. 39896 It would be bad public policy for the Commission to rely on speculative construction end dates to form the basis of a known and measurable change to test year costs. ETI' s own witness Mr. Cicio admitted that in-service dates can be uncertain. . .. Similarly, costs can change upward or downward. For this reason, the Commission has typically followed the policy that proper ratemaking requires that a utility actually build the transmission infrastructure suggested by its projections, and then seek to account for that investment on a historical basis in a future rate case. In Docket No. 28906, for example, the Commission held that LCRA' s projections of future transmission investment did not support a finding that its projected capital needs satisfied the known and measurable test. It is similarly unreasonable for ETI to make a post-test year adjustment associated with transmission projects that are not serving any of its customers and that may or may not impact ETI' s transmission equalization expense, depending on when the projects are finally completed. 368 Third, in addition to the six transmission projects that are under development, another driver of the increased costs over the Test Year comes from ETI' s estimate that $43 .9 million will be spent to maintain transmission investments across the Entergy Transmission System. The intervenors contend that ETI has provided little to no evidentiary support for this estimate. State Agencies and Cities also point out the unfairness of allowing ETI to begin recovering $10. 7 million per year in its rates immediately based upon new transmission facilities, even though many of those new facilities will not come into service (and ETI will therefore not incur higher MSS-2 payments for those facilities) for many months. 369 Fourth, Cities points out that Entergy and the various Operating Companies have announced a plan to sell all of their transmission assets to a third party. That process is currently underway. The evidence suggests that, if and when that transaction is complete, ETI's MSS-2 expenses will disappear. 370 Finally, TIEC argues that there is no need to grant ETI's request for a pro Jonna adjustment to its test year MSS-2 expenses because the Company can avail itself of a TCRF if its Rate Year 368 TIEC Initial Brief at 47 (citing Docket No. 28906, Order at 6). 369 State Agencies Initial Brief at 12; Cities Initial Brief at 45. ° 37 Cities Reply Brief at 67-68; Tr. at 113-14; Cities Ex. 4 (Goins Direct) at 20-21. Admittedly, if these expenses disappear, ETI will still have to bear transmission expenses. However, it is impossible to know, at this time, what those expenses would be. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 114 PUC DOCKET NO. 39896 costs deviate substantially from its Test Year costs. Thus, if it turns out that ETI experiences an increase in its MSS-2 expenses during the Rate Year, the utility has cost recovery mechanisms at its disposal that could make it whole in a timely manner. Staff and State Agencies argue that only $1.7 million (representing ETI's actual Test Year expenses) should be approved in this proceeding. TIEC witness Pollock recommends approving a slight upward adjustment to account for the fact that ETI's MSS-2 expenses were substantially higher in the second six months of the Test Year than they were in the first six months. Mr. Pollock and TIEC recommend a pro Jonna adjustment equal to twice the amount of MSS-2 payments 371 incurred by ETI in the second six months of the Test Year, or $2. 7 million. Cities' witness Goins presented yet another alternative. Dr. Goins proposes to adjust the projected Rate Year costs for known expenses incurred after the Test Year. He proposed reducing the adjusted Rate Year MSS-2 expense to a Test Year level by applying a load growth adjustment using ETI' s own projected load growth as a benchmark indicator of the reasonable anticipated level of growth. (Cities invoke essentially the same "matching principle" argument regarding load growth that they raised with respect to PPCCs). The result of Dr. Goins' adjustment would be to would allow ETI to recover $4,103,850 in MSS-2 expenses. 372 ETI responds to these arguments on a number of fronts. It contends that the main driver of changes in MSS-2 expenses is the relative amount of equalizable transmission investment in the transmission system by ETI and the other Operating Companies, compared to their proportionate responsibility for that investment, based on each company's responsibility ratio. 373 ETI argues that the other elements of the formula are relatively stable, and do not vary significantly from year to 371 TIEC Ex. I (Pollack Direct) at 32-33. 372 Cities Ex. 4 (Goins Direct) at 20-21. 373 ETI Ex. 45 (Cicio Rebuttal) at 3-4. Responsibility Ratio is an allocator that reflects the relative contribution of each Operating Company to the System's coincident peak load - in other words, an Operating Company's coincident peak load divided by the System peak load, calculated on a rolling twelve-month average. ETI Ex. 39 (Cicio Direct) at 12. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 115 PUC DOCKET NO. 39896 year. 374 ETI contends its requested level of MSS-2 expense is based on a known and measurable change because it is based on the $184.9 million in additional transmission investment for all of the Operating Companies that ETI knows will occur and can reasonably measure. ETI points out that "the vast majority" of the planned transmission projects have received full funding approval and have been constructed or are on schedule to be completed before the end of the Rate Year, while the remaining amount is reasonably quantified and measured based on the budget and historical spending for maintenance of equalizable transmission facilities. 375 ETI also argues that its actual MSS-2 expenses have steadily trended upward since the Test Year. ETI explains as follows: [l]n the last month of the test year (June 2011), ETI's payments began to increase significantly, as the balance of relative equalizable investment levels shifted among the Operating Companies. ETI' s actual monthly payments have climbed steadily ever since, reaching $698,289 in the most recent actual month's bill (February 2012). Annualization of this most recent actual data yields an annual MSS-2 amount of $8.4 million, almost five times the test year level. In light of this trend in actual historical data, the notion of basing the MSS-2 expense in rates on the test year level is unreasonable on its face. 376 Thus, ETI contends its requested expense level is "consistent" with actual recent historical levels of MSS-2 expense. 377 ETI describes Cities' concern regarding load growth as a "red herring." ETI contends that load growth is not the cause of changes in MSS-2 costs. Instead, its MSS-2 increases are driven by the other Operating Companies' transmission investments, "separate and apart from, and unaffected by," any increase in ETI's load. 378 Moreover, ETI contends that load growth adjustments are not 374 Tr. at 763 and 780. 375 ETI Ex. 59 (McCulla Rebuttal) at 2-3; ETI Initial Brief at 88-89. 376 ETI Initial Brief at 90-91; Tr. at 784. 377 ETI Initial Brief at 91. 378 ETI Ex. 45 (Cicio Rebuttal) at 4-5; ETI Initial Brief at 93. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 116 PUC DOCKET NO. 39896 known and measurable and are not the proper subject of a post-test year adjustment for ordinary expenses such as MSS-2 costs. 379 Finally, if the Commission rejects its request for $10.7 million in MSS-2 costs, ETI suggests annualizing the most recent period of its actual MSS-2 costs, by multiplying its February 2012 MSS- 2 bill times 12, resulting in an amount of $8,379,480. ETI contends this would be more representative of expected Rate Year MSS-2 costs than the amounts proposed by the intervenors. 380 For largely the same reasons as were discussed relative to PPCCs, the ALls conclude that ETI failed to meet its burden to prove that its proposed Rate Year MSS-2 costs are known and measurable. The MSS-2 formula requires assumptions about a great number of variables. Changes to any of the variables could occur during the Rate Year, thereby altering the amount paid by (or received by) ETI during the Rate Year. The projects that underlie ETI's Rate Year request are largely not yet built, and might never be built. Additionally, much like with the PPCCs estimates, there is a wide gulf between the competing estimates by ETI, Cities, and TIEC of forecast Rate Year MSS-2 costs, illustrating the problem of deviating from actual Test Year data in an area that involves so many future contingencies and unknowns. The ALls are equally unconvinced by ETI's alternative proposal to multiply its February 2012 MSS-2 bill times 12, resulting in an amount of $8,379,480. ETI offered no evidence to establish that a single month's costs can serve as a reasonable representation of what ETI's future Rate Year MSS-2 costs will be. Moreover, February 2012 is outside of the Test Year. The intervenors presented substantial evidence to demonstrate that ETI' s estimate of its Rate Year MSS-2 costs cannot be considered known and measurable. For this reason, the ALls recommend that ETI's MSS-2 request be rejected. In its place, the ALls recommend that ETI be allowed to recover its Test Year MSS-2 costs of $1,753,797. 379 ETI Ex. 57 (May Rebuttal) at 12; ETI Initial Brief at 93. 380 ETI Ex. 46 (Considine Rebuttal) at 37; ETI Initial Brief at 32. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 117 PUC DOCKET NO. 39896 C. Depreciation Expense [Germane to Preliminary Order Issue No. 12] ETI currently has an annual depreciation expense of approximately $72.1 million. This expense is based on the previously approved depreciation rates. 381 ETI now requests depreciation rates that would result in an annual depreciation expense of approximately $86 million. This requested amount represents an increase in the annual depreciation expense of approximately $13.9 million - almost 20 percent - from the current annual depreciation expense. 382 The depreciation expense ultimately included in retail rates, however, will be derived by applying the Commission approved rates to the test year end plant balances as of June 30, 2011. The other parties have accepted the vast majority of ETI' s recommendations, but take issue with the Company on a few issues related to generation, transmission, distribution, and general plant accounts. Staff recommends an annual depreciation expense of approximately $78.2 million, an increase of approximately $6.1 million from the current annual depreciation expense. 383 Cities recommend an annual depreciation expense of approximately $67.6 million. 384 The identical positions of ETI, Staff, and Cities on depreciation issues are set forth in the following table: 385 Plant Group Approved ETI Proposal Staff Proposal Cities Proposal Hydro $7,137 $245 $245 n/a Production Regional Trans. $685,351 $685,351 $685,351 n/a &Market Operations General $4,175,311 $5,946,949 $5,946,949 n/a Amortized Plant 381 ETI Ex. l3 (Watson Direct) Attachment DAW-1. Appendix Bat 3. 382 ETI Ex. 13 (Watson Direct) at 7. 383 Staff Ex. 2 (Mathis Direct) at 8. 384 Cities Ex. SC (Pous Depreciation Study) at 2. 385 ETI Ex. 13 (Watson Direct) at 7; Staff Ex. 2 (Mathis Direct) at 7-8; Cities Ex. SC (Pous Depreciation Study) at 7, 8, and 34. SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE118 PUC DOCKET NO. 39896 The differing positions of ETI, Staff, and Cities on depreciation issues are set forth in the following table: 386 Plant Group Approved ETI Proposal Staff Proposal Cities Proposal Steam $17,497,781 $18,660,946 $14,709,942 n/a Production Transmission $13,679,827 $16,493,761 $16,417,727 $13,451,479 Plant Distribution $32,110,774 $40,493,392 $38,806,863 $33,186,546 Plant General Plant $3,943,450 $1,604,644 $1,604,644 $973,519 General Plant $0 $2,134,924 $0 n/a Reserve Deficiency TOTAL $72,099 ,631 $86,020,212 $78,171,721 n/aj/5/ The competing positions of ETI, Staff, and Cities reflected in the table above are primarily the result of different: (1) net salvage rates for certain accounts; (2) remaining life parameters for certain accounts; and (3) treatment of a potential general plant reserve deficiency. Cities witness Pous also questions the reliability of the data employed by ETI witness Watson in the performance of his study. An analysis of the competing net salvage rates and life parameters for each account is presented in detail below, organized by plant and account group. 1. Terminology and Methodology Depreciation is a method of allocating the loss of the service value, not restored by current maintenance, over the useful life of an asset. This loss may be caused by wear and tear, decay, obsolescence, or changes in demand. 388 386 ETI Ex. 13 (Watson Direct) at 7; Staff Ex. 2 (Mathis Direct) at 7-8; Cities Ex. 5C (Pous Depreciation Study) at 7, 8, and 34. 387 A total value of Cities' adjustments in this format would be out of context and is therefore not provided in this table. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 119 PUC DOCKET NO. 39896 Within the context of a rate case, the purpose of depreciation is to allow a company to recover the cost of an asset over the asset's useful life. Ideally, the cost of the asset is spread out evenly across the years the asset is in service, thus recovering the cost of the asset from the customers who receive the benefit of the asset. 389 Both ETI and Staff use the remaining-life technique, average life group procedure, and straight-line method to calculate the depreciation rate. 390 The basic formula for the remaining life technique is presented below. 1 - book reserve ratio - net salvage ratio} depreciation rate ( %) = { . . . ll composite remm.nmg z e * 100 For example, if an asset has a book reserve ratio of 0.5 (i.e., 50 percent of the asset's value has already been recovered through prior depreciation expense), a net salvage ratio of zero (i.e., the asset will cost nothing to retire, or all retiring costs will be recovered through its subsequent sale), and the composite remaining life is ten years (i.e., the asset is expected to remain in service for another ten years), then the depreciation rate will be 5 percent (i.e., { [ (1 - 0.5 - 0) I 10 ] *100 }). By operation of the remaining-life formula, a greater net salvage value will reduce the numerator and result in a lower depreciation rate and a lower depreciation expense. Likewise, a lower net salvage value will increase the numerator and result in a higher depreciation rate and a higher depreciation expense. Similarly, a longer remaining-life will result in a lower depreciation rate and lower depreciation expense, and a shorter remaining-life will result in a higher depreciation rate and a higher depreciation expense. Because net salvage and remaining-life values are the two contested variables in the remaining-life formula, a clear explanation of net salvage and remaining-life will be helpful. 388 Staff Ex. 2 (Mathis Direct) at 8. 389 Staff Ex. 1 (Mathis Direct) at 8-9. 390 ETI Ex. 13 (Watson Direct) at 15; Staff Ex. 2 (Mathis Direct) at 10-11. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 120 PUC DOCKET NO. 39896 Net Salvage Value. Net salvage is calculated by taking the amount received for an asset as a result of its sale, reuse, or reimbursement, and subtracting that amount from the cost associated with retiring the asset. This figure is then divided by the original cost of the asset to determine the net salvage ratio. For example, if an asset with an original cost of $200 is resold for $20, but it costs the owner $10 to ship the asset to the purchaser, then the net salvage value of that asset would be $10 ($20 - $10), and the net salvage ratio of that asset would be 5 percent ($10/$200). ETI witness Watson and Staff witness Mathis used different methods of calculating a net salvage rate. 391 Mr. Watson took the average (mean) of recorded net salvage values for groups of successive years (rolling bands), and then selected the net salvage rate from among these averages. 392 Ms. Mathis also used rolling band averages (means), but then took the median from a representative group of rolling bands when the historical salvage data would have otherwise produced what Mr. Watson considers skewed results. 393 Ms. Mathis' method of calculating net salvage rates follows recent Commission precedent. 394 As Mr. Watson explained at the hearing, it is appropriate to infer acceptance of a methodology by looking at whether the Commission adopted the conclusions that the methodology produced. 395 In other words, if the Commission adopts the conclusions, then by inference the Commission has adopted the methodology used to derive those conclusions. Thus, it is necessary to examine recent litigated rate cases to ascertain Commission precedent. In the most recent fully-litigated rate case, Docket No. 38339, 396 Staff disagreed with CenterPoint' s depreciation witness, Mr. Watson, concerning the net salvage rates for five 391 Tr.at415-416. 392 ETI Ex. 13 (Watson Direct) at 20-21. 393 Id. at 22-23, 32-33. 394 Tr. at 1766; Staff Ex. 9 (Docket No. 38339 Final Order) at FoF 126, 128, 130, and 131. 395 Tr. at 397. 396 Application of CenterPoint Energy Houston Electric, UC, for Authority to Change Rates, Docket No. 38339 (June 23, 2011). SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 121 PUC DOCKET NO. 39896 accounts. 397 In its order, the Commission adopted Staffs recommended net salvage rates for four out of those five accounts for which Staff disagreed with Mr. Watson. 398 Staffs method for 399 calculating net salvage rates is the same in the present case as it was in the CenterPoint rate case. ETI argues that the use of a median, as employed by Ms. Mathis, is not a sufficiently rigorous or expansive approach to depreciation analysis. According to ETI, depreciation training and texts, as well as authoritative statistical texts, favor the average, or mean, not the median, as the best indicator of the central tendency of a data set. ETI argues that this is particularly the case because depreciation analysis requires careful consideration of trends over time. 400 ETI then offers the following comments: [Ms. Mathis] agreed in response to a hypothetical that the median value of an initial period of ten years of +5% net salvage, followed by one year of 0% salvage, followed by the most recent period of ten years of -5% salvage, would be 0%. This hypothetical plainly illustrates how reliance on the median can overlook data trends. In the hypothetical, if the depreciation analyst would otherwise wish to give more weight to the most recent historical period as indicative of conditions going forward, 401 the use of the median would obscure that important trend information. A close examination of the hypothetical shows that in the case posited by ETI, however, the median and the mean are identical: both are zero. While the use of the median would produce a result that ignores the trend that ETI says should be taken into account, the mean produces the same result. Changing the hypothetical produces no more clarity. If the examination was of a period that had ten years of positive five percent salvage value, followed by one year of zero percent net salvage value, followed by the most recent 10-year period, which had negative 10 percent net salvage value, the median would still be zero but the mean would be negative 2.38 percent. This appears to support the trending argument advanced by ETI. If the analysis then focuses on a different hypothetical, one 397 Tr. at 401-402. 398 See Staff Ex. 9 (Docket No. 38339 Final Order); Tr. at 402. 399 Tr. at 415-416. 400 ETI Initial Brief at 105. 401 Id. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 122 PUC DOCKET NO. 39896 with ten years of positive 10 percent net salvage value followed by one year of zero percent net salvage value, with the most recent ten-year period having negative five percent net salvage value, the results are more perplexing. The median is still zero, but the mean, which ETI contends will recognize the trending, is 2.38. Although this does in some respects recognize the trend to a negative salvage value, it does not recognize it as well as the median. Principles and Procedures of Statistics, by Steel and Torrie, states: "Certain types of data show a tendency to have a pronounced tail to the right or the left. Such distributions are said to be skewed, and the arithmetic mean may not be the most informative central value." Where the average of the incomes of a group of individuals is required, and most of those incomes are low, the mean income could be considerably larger than the median. In Docket No. 38339, Staff posed the following example, which the AU s found both informative and persuasive: Suppose a sample of 50 incomes from professional baseball players was taken that happened to include the salary of two of the most highly compensated players in the league today. As a result, the mean of the salaries would likely be far greater than the median salary, because the use of the median would be skewed by the very high salaries. The median would likely provide a more accurate measure of the central tendency of the salaries. Such circumstances are found where using the median to find the central tendency prevents outliers in data that "skews" or shows extreme variations rather than showing more symmetrical variations. The ALls believe this is as accurate today as it was during the Docket No. 38339 timeframe. They therefore find that the use of the median is the more appropriate methodology for determining net salvage value. Remaining Life. Composite remaining life is the weighted average remaining life of the property account for a group of all vintages. The average remaining life represents the future years of service expected for the surviving property. There are numerous ways to calculate the remaining life (life parameter) of a group of assets in a depreciation study. Examples include the interim retirement rate method and the retirement (actuarial) rate method. The interim retirement rate method uses interim retirement curves to model (predict) the retirement of individual assets within plant accounts. Alternatively, the retirement SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE 123 PUC DOCKET NO. 39896 (actuarial) rate method uses historical mortality data for a group of assets and compares that data to various known patterns of industrial asset mortality rates (Iowa Curves). If the historical data creates a pattern of mortality that closely follows one of the Iowa Curves, then that Iowa Curve may be used to approximate the remaining lives of that given group of assets in the future. Whether the historical mortality data creates a pattern that closely follows a given Iowa Curve is determined through plotting both sets of data (the historical mortality data and the Iowa Curve) on a graph and quantifying the closeness of fit through statistical analysis and visual examination. Mr. Watson used multiple methods to calculate the remaining lives of assets, depending on the asset. Generally, he used the retirement rate (actuarial) method. 402 However, to calculate the remaining life of production plant accounts, he used the interim retirement rate method. 403 Ms. Mathis disagreed with the use of the interim retirement rate method because the Commission has rejected the application of interim retirement rates of production plant, as they are based on future projection of retirements, for ETI and Central Power and Light Company in Docket Nos. 16705404 and 14965,405 respectively. ETI argues that the life span procedure, without the use of interim retirement curves, is unrealistic in its assumption that all production plant assets are "depreciated (straight-line) for the same number of periods and retire at the same time (the terminal retirement date)." Use of interim retirements is an important refinement that adds accuracy to the determination of the depreciation rates according to ETI. Mr. Watson offered the following explanation: Adding interim retirement curves to the procedure reflects the fact that some of the assets at a power plant will not survive to the end of the life of the facility and should 402 ETI Ex. 13 (Watson Direct) at 16. 403 Staff Ex. 2 (Mathis Direct) at 14. 404 Application ofEntergy Gulf States, Inc., for Approval of its Transition to Competition to Competition Plan and the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to Recover a Surcharge for Under-recovered Fuel Costs, Docket No. 16705 (Oct. 14, 1998). 405 Application of Central Power & Light Company for Authority to Change Rates, Docket No. 14965 (Oct. 16, 1997). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 124 PUC DOCKET NO. 39896 be depreciated (straight-line) more quickly and retired earlier than the terminal life of the facility. 406 ETI contends that this issue presents a unique situation where all the experts agree with the theoretical soundness of Mr. Watson's approach, but Mr. Pous and Ms. Mathis recommend its rejection due to the existence of contrary Commission precedent. The impact of their position is a $1,558,081 reduction to depreciation expense, based on December 31, 2010, plant balances. Mr. Pous generally supports the use of interim retirements because "I think it's right,"407 and he uses the method in other jurisdictions, where it is a prevalent practice. Ms. Mathis "also appears to recognize the theoretical soundness of utilizing interim retirements."408 Even in Docket No. 16705, the precedent cited by Mr. Pous and Ms. Mathis, the Staff depreciation witness agreed that the use of interim retirements was appropriate, though not blessed by the Commission. ETI argues that use of interim retirements reflects the undisputable fact that "generating units will have retirements of depreciable property before the end of their lives.''409 ETI is correct that neither Ms. Mathis nor Mr. Pous provide any reasoning behind the prior Commission precedent. Moreover, it is also true that the Commission precedent is relatively old at this point (dating back to the mid-1990s) and apparently has not been revisited in any recent cases. ETI argues that the Commission has in at least one other case used interim retirements (Docket No. 15195410), but provides little more than that comment to support the concept. It is true that in concept, interim retirements are determined in much the same fashion as other elements of depreciation analysis. Primarily based on historical accounting data, the analyst identifies characteristics in the history of the data upon which to base a reasoned assessment of retirements going forward, which is similar to what occurs in determining asset lives or net salvage. Interim 406 ETI Ex. 13 (Watson Direct) at Ex. DAW-I, at 7-8. 407 ETI Ex. 7 I (Watson Rebuttal) at 7 I, citing Pous Deposition at 49, 5 I. 408 Staff Ex. 2 (Mathis Direct) at I2-l3. 409 ETI Ex. 13 (Watson Direct) at Ex. DAW-I, p. 8. 410 Application of Texas Utilities Electric Company for the Reconciliation of Fuel Costs, Docket No. I 5 I 95 (Aug. 26, I 997). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 125 PUC DOCKET NO. 39896 retirement determinations are supported by their own Iowa Curves, just as is the analysis of plant lives. Although the AU s are persuaded by ETI' s arguments that the use of interim retirements may be the more theoretically correct methodology to employ, Commission precedent clearly disfavors the use of interim retirements and the A.Us are reluctant to rule contrary to Commission precedent. Accordingly, the Al.Js find that the retirement (actuarial) rate method, rather than the interim retirement method, should be used. 2. Production Plant (a) Lives Mr. Watson primarily used the life span method to calculate remaining lives of the production plant accounts. 411 The life span method estimates a production plant's life based on consultation with utility management, financial, and engineering staff.412 However, he used interim retirement methodology to reduce the remaining lives determined by the life span method. Staff does not dispute the remaining lives determined by the life span methodology, but does dispute the use of interim retirements. For the reasons discussed in Section VII.C.l, ETI should not be allowed to use the interim retirement methodology to adjust downward the remaining lives of its production plant accounts. Cities witness Pous disputed only the remaining life determination for ETI's Sabine Power Plant Units 4 and 5, ETI's largest and newest gas fired generating units. Mr. Pous recommended a life span for Sabine Units 4 and 5 of 64 years based on assessment of the units, comparison to the estimated life span of similar units owned by ETI as well as other gas fired generating units across the country. ETI proposes a 60-year life for the two units. Mr. Pous noted that a "64-year life span recommended for Sabine Units 4 and 5 is consistent with the life span proposed by the Company for its Lewis Creek 1 generating unit. Lewis Creek Unit 1 is an older, smaller, and generally less 411 ETI Ex. 13 (Watson Direct) at 16. 412 Staff Ex. 2 (Mathis Direct) at 14. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 126 PUC DOCKET NO. 39896 efficient generating unit than Sabine Units 4 and 5. Cities contend that there is no basis or logic for assigning a shorter life span for a more capital-intensive asset that is newer, larger, and generally more efficient."413 ETI witness Watson explained that he primarily relied on the determination of Company personnel to arrive at the 60-year life for the Sabine Units. Although Cities attempted to cast doubt on Mr. Watson's determinations regarding the life of these units, it is clear that his determinations are based on conversations with ETI various generation personnel and that those conversations confirmed that based on evaluation of a variety of considerations, including age, operational role, level of funding, unit condition, and operational risk, 60 years constitutes a reasonable threshold for the expected life of Sabine Units 4 and 5. It is also clear that comparisons to Lewis Creek Unit 1 are not appropriate. Lewis Creek Unit 1 has significant differences, which explain its longer life-span. Unlike the Sabine Units, ETI is planning to spend in excess of $100 million to refurbish the Lewis Creek critical equipment over the next three years to sustain operating reliability. ETI is not performing similar refurbishment activities at Sabine. 414 The Sabine Units are projected to be "must-run" units. This means that these units are, for the most part, deployed to operate whenever they are available for service. Mr. Pous compared these units to EAi's Lake Catherine Units 1 & 2, 415 but ETI contends this is not a reasonable comparison. EAi's Lake Catherine Units 1 & 2 are not "must-run" units. They experience very infrequent operation and are not projected to run much in the future. Other things being equal, according to ETI, this would justify the longer 67-year life span assigned to these Arkansas units, because they would not be experiencing the wear and tear of daily operation.416 The explanations offered by ETI for the 60-year life of the Sabine Units 4 and 5 generating facilities are convincing. It appears that Mr. Watson engaged knowledgeable people within ETI to 413 Cities Ex. 5C (Pous Depreciation Study) at 9. 414 ETI Ex. 51 (Garrison Rebuttal) at 3. 415 Cities Ex. 5 (Pous Direct) at 7-8. 416 ETI Ex. 51 (Garrison Rebuttal) at 3. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 127 PUC DOCKET NO. 39896 gather pertinent information and applied that information appropriately. The comparison to Lake Creek units is not appropriate given the planned refurbishment of those units. Similarly, the comparison to the Lake Catherine units also fails. A unit that does not carry the "must-run" designation can easily be expected to perform longer than a unit, such as the Sabine Units, that carries the "must-run" designation. Accordingly, the ALls find that ETI' s choice of a 60-year life for the Sabine Units 4 and 5 is reasonable. (b) Net Salvage Value In determining the net salvage attributable to production plant, ETI witness Watson started with the negative 5 percent net salvage factor approved most recently for ETI in PUC Docket No. 16705. This is a net salvage value that the Commission has adopted in a number of cases for production plant. 417 Mr. Watson testified that the net salvage calculation must reflect known changes in the cost of retiring production plant since the net salvage factor was last set. Accordingly, Mr. Watson's study used the Handy-Whitman labor index to calculate the change in labor costs applicable to removal activity for the years 1997 to 2010. Consideration of the increases in labor costs over this 13-year period resulted in an increase in the cost of removal, and a corresponding increase in the level of negative net salvage, from negative five percent to negative 8.5 percent. 418 Both Staff witness Mathis and Cities witness Pous disagreed with ETI's proposal for production plant net salvage. Ms. Mathis proposed that the existing negative 5 percent net salvage factor be retained. Ms. Mathis stated that Mr. Watson's analysis is flawed for three reasons: • First, Mr. Watson did not calculate a gross salvage value for each plant. This is a necessary element of the fundamental net salvage rate calculation. 419 • Second, Mr. Watson unreasonably assumed that all steam production plants would be demolished at the end of their estimated remaining lives without any consideration of 417 Staff Ex. 2 (Mathis Direct) at l 7. 418 ETI Ex. 13 (Watson Direct) at Ex. DAW-l, at 64. 419 Staff Ex. 2 (Mathis Direct) at 16-17. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 128 PUC DOCKET NO. 39896 reuse of the unit after refurbishment, or mothballing the unit or selling the unit in the event of deregulation of the generating function of the utility. 420 • Third, Mr. Watson did not provide detailed plans for the actual demolition of each of its power plants. The Commission has consistently approved negative five percent net salvage rates for production plants if detailed plant-specific and reasonable demolition cost studies were not filed by the utility. 421 ETI responds that Staffs recommendation fails to account for the fact that the negative 5 percent benchmark is stale, having been established in a Commission proceeding 35 years ago. Since that time, "labor costs have escalated by 267 percent with the rational expectation that they will continue to increase at least with inflation."422 Cities witness Pous recommended moving from the current negative five percent net salvage to a positive 5 percent net salvage; i.e., that it should be determined that the gross salvage from the power plants will exceed the removal cost. Mr. Pous stated that he bases this claim on the ETI' s actual experience over the past 45 years as well as current trends within the industry in the last 14 years. According to Mr. Pous, ETI has retired many units since 1965 and demolished or sold the units and achieved a range of net salvage values from zero percent net salvage to positive 180 percent. 423 Other utilities in Texas and elsewhere have also experienced positive net salvage levels. 424 Mr. Pous testified that since 1998 over 1,000 generating units have been sold, and in all instances resulted in positive net salvage. 425 He also claims that his positive five percent production net salvage is consistent with the Commission's decision in the most recent SPS case, Docket No. 32766, where Mr. Watson was hired by SPS as a depreciation witness and the 420 Id. at 17. 421 Id. 422 ETI Ex. 71 (Watson Rebuttal) at 17, 19. 423 Cities Ex. 5 (Pous Direct) at 15. 424 Cities Ex. 5C (Pous Depreciation Study) at 11; Cities Ex. 5 (Pous Direct) at 15-16. 425 Cities Ex. 5C (Pous Depreciation Study) at 11. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 129 PUC DOCKET NO. 39896 Commission ultimately approved a positive five percent net salvage. 426 As ETI notes, however, the SPS rate case was the result of settlement427 and is of little precedential value. ETI argues that Cities witness Pous appears to primarily base this claim on the fact that the sale of utility plants in circumstances bearing no relationship to depreciation analysis has yielded gains that Mr. Pous characterizes as "positive net salvage." He uses as examples sales that form a part of the restructuring of the Texas utility business to introduce retail competition. Ms. Mathis also concluded, without elaboration, that ETI' s production plant net salvage analysis is flawed because it does not consider the possibility that the unit could be sold as a consequence of deregulation. Neither Ms. Mathis nor Mr. Pous, however, pointed to any instance in which the Commission has adopted such an approach to determining net salvage. ETI contends that this argument should be rejected for a number of reasons. It argues that although there is no precedent supporting Ms. Mathis' and Mr. Pous' approach, there is clear recent precedent rejecting the inclusion of sales in depreciation analysis. 428 The sales referenced by these witnesses are unique and unpredictable events, as should be evident from the use of the restructuring of the utility industry as an example of this type of activity. Indeed, at this time the Texas Legislature has halted for the foreseeable future any ETI move to competition. For purposes of depreciation analysis, net salvage is aimed at determining the salvage received at the end of the plants' useful lives. Mr. Pous' analysis necessarily assumed that, due to the sale, the life of the plants will be truncated. Yet he made no adjustment to production plant lives to account for the effect of theoretical sales.429 ETI also contends that Mr. Pous' other examples of positive net salvage are equally unavailing. Mr. Pous points to ETI's retirement of Neches Station as an example of positive 426 Cities Ex. 5 (Pous Direct) at l 7. 427 See ETI Ex. 71 (Watson Rebuttal) at 6. 428 See Application ofAEP Texas Central Co. for Authority to Change Rates, Docket No. 33309, FoF l 07, 108, 112 (Mar. 4, 2008) (proceeds from sale of building properly removed from depreciation analysis as non-recurring item). 429 ETI Ex. 71 (Watson Rebuttal) at 5-7. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE 130 PUC DOCKET NO. 39896 salvage,430 but fails to mention that: (1) this outcome was uniquely the result of insurance proceeds received by ETI after a boiler explosion; and (2) the proceeds flowed back to customers via means other than depreciation rates. 431 ETI contends that Mr. Po us' claim that a contractor paid $1 million for the right to demolish a power plant, apparently based on unrecorded hearsay conversations, and without any information from Mr. Pous regarding the facts and circumstances surrounding the transaction, proves nothing. Finally, Mr. Pous stated that Mr. Watson's adjustment to the net salvage rates is flawed because it does not adequately reflect the increase in scrap metal prices in recent years. ETI responds that although scrap metal prices have gone up recently, it is unknown what the prices will be in the future, and these commodity prices have proven to be quite volatile and unpredictable. 432 According to ETI, it is not reasonable to assume, as does Mr. Pous, that prices will stay indefinitely at what is their historically highest level. ETI argues that Mr. Pous' method is based on speculation and broad, conclusory opinions regarding economic trends, as to which he makes no attempt to actually arrive at a quantifiable analysis that yields his unprecedented positive net salvage recommendation. 433 Mr. Pous' testimony that net salvage value should be revised to reflect a value of positive 5 percent is seriously flawed. First, pointing to a settled case as precedent carries no weight. Second, attempting to draw conclusions from sales that were forced to comply with the regulatory framework and apply those conclusions to an entity that is not subject to the same regulatory framework is equally flawed. Finally, Mr. Pous attempted to use ETI's own experience to support his position ignores the fact that ETI' s experiences were driven by factors that were unique to ETI at the time and circumstances involved; they do not support the more universal application urged by Mr. Pous. 43 ° Cities Ex. 5 (Pous Direct) at 14. 431 ETI Ex. 46 (Considine Rebuttal) at 49-50. 432 ETI Ex. 71 (Watson Rebuttal) at 17-18. 433 ETI Initial Brief at 103. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 131 PUC DOCKET NO. 39896 Ms. Mathis' analysis, in some respects, suffers from the same flaws as Mr. Pous'. Nevertheless, some of her points carry more weight. The AUs believe that Mr. Watson is correct that labor costs have increased since the negative five percent net salvage value was first established by the Commission. However, that is not the end of the story. Are there other factors that also have changed in the corresponding time period? There is no evidence on this point, and that is the crux of the matter. As Ms. Mathis argues, there is only one way that all the changing values can be evaluated; through the introduction of plant-specific demolition cost studies. Had studies of that nature been provided, the parties would have been able to evaluate them and provide a supportable, fully-vetted recommendation. The AUs recommend that the Commission find that a negative 5 percent net salvage value for production plant is appropriate. (c) Depreciation Reserve TIEC argues that $1.1 million of ETI's requested $13 million increase in depreciation expenses is related to ETI' s production plant assets. 434 ETI has a $92,537 ,000 surplus in production plant assets. A surplus depreciation reserve occurs when the theoretical reserve (the reserve that would exist if the current proposed rates had been in place in the past) exceeds the per book depreciation reserve. According to TIEC, this indicates that ETI customers have overpaid the value of production plant assets. 435 Since ETI has already over-recovered the value of the production plant assets, there is no valid reason to seek any additional recovery. TIEC contends that ETI has not shown why it needs to increase production depreciation rates at this time given that the production depreciation reserve has a considerable surplus. Therefore, it argues, $1.1 million of the proposed increase should be rejected. ETI rejects TIEC' s recommendation because it is clearly contrary to Commission policy and precedent. According to ETI, the Commission has consistently adopted the remaining life, straight- line method for determining depreciation rates. 436 This method requires that the remaining life of 434 ETI Ex. 13A (Watson Workpapers) at Appendix B. This figure is derived by subtracting the expenses from the existing production plant account from the proposed production plant account. 435 TIEC Ex. l (Pollock Direct) at 36-37, Ex. JP-5. 436 See Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 33309, PFD at SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 132 PUC DOCKET NO. 39896 the asset be determined, and depreciation rates established to recover the asset's remaining cost in equal installments over that life. In this way, by the end of the life, the costs will be recovered. Mr. Pollock's approach ignores these principles, and seeks to look back in time to compare how the depreciation rates now proposed would have affected the recovery in the past. Those past depreciation rates, however, were authorized for use by the Commission. ETI argues that depreciation rates are at all times estimates, subject to adjustment using updated studies, and there is no reason for adoption of Mr. Pollock's alternative. Finally, the Commission expressly rejected adjustment to the outcome of remaining life depreciation determinations based on differences between theoretical and book depreciation reserves in CenterPoint Docket No. 38339. 437 The ALls agree with TIEC that the Commission's decision in Docket No. 38339 is not four-square on point with this case. That is not sufficient, however, to overcome the arguments advanced by ETI in favor of its position in the current case. The Commission has consistently used the remaining life, straight-line methodology for determining depreciation rates, and that methodology requires that the remaining life of the asset be determined, and depreciation rates established to recover the asset's remaining cost in equal installments over that life. Mr. Pollock's proposal ignores that consistently applied methodology. The AU s recommend that the Commission approve ETI's recommended treatment of the production plant depreciation reserve. 3. Transmission Plant (a) Lives Mr. Watson's study presents ETI's life proposal for transmission Accounts 350.2 to 359, a 438 total of eight accounts. Neither Staff witness Mathis nor Cities witness Pous took issue with any 127-128 (Mar. 4, 2008); Application of CenterPoint Electric Delivery Company for Authority to Change Rates; Docket No. 39339, PFD at 86 (Dec. 3, 2010); Application of Oncor Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 35717, PFD at 153-154 (June 2, 2009). 437 ETI Ex. 71 (Watson Rebuttal) at 75-77 (citing CenterPoint Docket No. 38839 PFD). 438 ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 30-36. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 133 PUC DOCKET NO. 39896 439 of the recommended lives for transmission plant accounts. Accordingly, the ALJs recommend that the Commission adopt ETI's proposed lives for these accounts. (b) Net Salvage Value Staff disagrees with Mr. Watson's recommendations for two of the eight transmission accounts, and Mr. Pous disagrees regarding three of the accounts. The parties' positions on transmission net salvage values in dispute are set out below: Transmission Account Net Salva2e Account Current ETI Staff Cities Net Salvage Proposal Proposal Proposal Value 352-Structures & Improvements -5% -10% -5% -10% 353-Station Equipment +5% -20% -20% 0% 354-Towers & Fixtures -5% -20% -5% -20% 355-Poles and Fixtures -25% -30% -30% -15% 356-0verhead Conductors & -20% -30% -30% -10% Devices (i) Account 352-Structures & Improvements Mr. Watson's analysis of this account, and for all the accounts in his study, included the examination of trends and bands for numerous years. For Account 352, he found the five-year and ten-year moving averages for the years 2008-2010 particularly telling. 440 A moving average is a rolling average that updates each year to include the additional year as part of the average for the longer period under study. Mr. Watson testified that his recommendation of negative 10 percent net salvage is consistent (albeit less negative) with the five-year and ten-year moving averages for 2008, which range from negative 16.31 percent to negative 16.80 percent. Although the moving averages 439 Staff Ex. 2A (Mathis Direct) at 21; Cities Ex. 5 (Pous Direct) at 28. 440 ETI Ex. 71 (Watson Rebuttal) at 56. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 134 PUC DOCKET NO. 39896 for 2009 and 2010 appear more positive, this was the result of a large, atypical gross salvage in 441 2009. Cities propose no change to Mr. Watson's recommendation. Staff witness Mathis recommended a net salvage rate of negative five percent for Account 352. This recommendation is based on analysis of historical salvage data for the period of 1984 through 2010. Specifically, the three-year moving average for the same period produces a net salvage rate of negative 5.53 percent, which is very close to the currently approved net salvage rate for this account. Moreover, an examination of the mean and median rolling band averages for Account 352 shows a range of net salvage rates between positive 0.08 percent and negative 6.83 percent. 442 Thus, according to Ms. Mathis, the net salvage rate of negative 5 percent is a reasonable estimate based on the available historical data. In response to Mr. Watson's contention that the 2008 moving average is the most important, Ms. Mathis pointed out that the 2009 five-year and ten-year moving averages feature positive 16.66 percent and positive 4.45 percent net salvage rates, respectively. Moreover, the 2010 five-year and ten-year moving averages feature positive 25 .13 percent and positive 6. 75 percent net salvage rates, respectively. 443 Ms. Mathis stated that if it is a sound depreciation methodology to select a net salvage rate based on recent five-year and ten-year moving averages, then the rate for this account should be significantly greater than either Ms. Mathis' or Mr. Watson's recommendation. 444 Although the moving averages cited by Ms. Mathis for 2009 and 2010 appear to belie the arguments raised by Ms. Watson, the AlJs are persuaded that those are significantly influenced by the atypical gross salvage resulting from the 2009 sale of a spare transformer, an asset whose cost is booked to an entirely different account. If, as claimed by Mr. Watson, the sale was sufficiently 441 ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 65. The atypical gross salvage resulted from the sale of a spare transformer, an asset whose cost is booked to an entirely different account. ETI Ex. 71 (Watson Rebuttal) at 57. The atypical amount is shown at Appendix E-2 at 1 of Mr. Watson's depreciation study. 442 Staff Ex. 2 (Mathis Direct) at 22, Appendix Cat l. 443 Id. 444 According to Ms. Mathis, if 2009' s moving averages are adopted, the net salvage ratio should be around positive 4.45 percent or positive 16.66 percent If 2010's moving averages are adopted, the net salvage ratio should be around positive 6.75 percent or positive 25.13 percent SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 135 PUC DOCKET NO. 39896 atypical, it would influence both 2009 and 2010 moving averages, making them unreliable. Accordingly, the Alls recommend that the Commission adopt ETI' s negative 10 percent net salvage value for Account 352. (ii) Account 353~Station Equipment Similar to Account 352, a large atypical positive salvage amount in this account makes the most recent moving average appear more positive than the history would otherwise suggest. 445 Mr. Watson recommended setting net salvage at negative 20 percent, which he contended is a reasonable middle ground between the values suggested by the five-year and ten-year moving averages for transaction year 2010 (which show net salvage of negative 14.42 percent and negative 20 percent, respectively). 446 Ms. Mathis agreed with the Company's proposal on this account. Although Mr. Pous acknowledged that retention of the current Commission-approved positive five percent net salvage is supported by ETI's experience, he ultimately opted for a recommendation that the net salvage value be reduced to zero percent. Mr. Pons noted that the actual per book data for a five-year band and a ten-year band are a positive 117 .04 percent and a positive 31.95 percent, respectively. 447 Mr. Pous stated that his analysis does not ignore the positive net salvage recorded by ETI because of the sale of transmission investment, rather he testified that: the Company has reported five separate sales during the past 22 years, or about once every four years. Such activity cannot be considered an 'unusual circumstance' or an outlier, and should be taken into consideration as an event that may continue to occur in the future. In a proper evaluation phase of a depreciation study, recognition of some level of future sales is appropriate. 448 445 The atypical amount is shown at Appendix E-2, p. 1 of 10 of Mr. Watson's depreciation study. 446 ETI Ex. 13 (Watson Direct) at Ex. DAW-I at 65. 447 Cities Ex. SC (Pous Depreciation Study) at 21, 23. 448 Id. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 136 PUC DOCKET NO. 39896 Mr. Pous' analysis also reflected that transformers, which contain large quantities of copper and produce gross salvage when retired, comprise a significant level of investment in this account, but were underreported in the five-year and ten-year band analyses. 449 Mr. Pous stated that, given the significant increase in the value of copper, the future proportionate retirement of transformers will result in future net salvage values being less negative or more positive than the historical data. ETI responds that Cities' criticism that the per book data in Mr. Watson's workpapers show a large positive net salvage value for the five-year and ten-year bands is unfounded. According to ETI, Mr. Watson's workpapers clearly indicate that adjustments were required and made to the per book data for unique transactions involving sales and storm activity. As to sales, the workpapers 450 show that in the 26 years of data for Account 353, there were three occasions with very large sales proceeds for the sale of substations. As to storm activities, the same workpapers show only one occasion in 26 years where gross salvage amounts were recorded. ETI contends that these unique events are properly excluded from net salvage analysis and Mr. Pous' reliance on the per book data to establish positive net salvage is erroneous. With respect to Mr. Pous' concem's relating to the price of copper, ETI responds that Mr. Pous' reliance on copper's scrap value is pure speculation, unsupported by any ETl-specific data regarding the amount of copper at issue, or any consideration of the offsetting significant and increasing labor costs involved in the removal of large station transformers. As explained by Mr. Watson, it appears to the AlJs that the adjustments made were, indeed, required because of the unique nature of the events they reflected. The AU s also find that Mr. Pous' concerns relating to the price of copper are speculative. Coupled with the fact that Staff supports ETI's proposed net salvage value, the AUs recommend that the Commission approve ETI's recommended negative 20 percent net salvage value. 449 Id. at 22. 450 ETI Ex. 13A (Watson Direct) Workpaper on CD, "Entergy Net Salvage Transmission Distribution General" Spreadsheet, "Data Adjustments" Tab, Account 353. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 137 PUC DOCKET NO. 39896 (iii) Account 354-Towers and Fixtures Although there is limited experience available for this account, the five-year and ten-year moving averages for transaction year 2010 show a substantial level of negative net salvage (negative 299 percent and negative 233 percent, respectively). Taking into account the low level of retirement experience, Mr. Watson stated that he moderated the outcome by recommending moving 451 to negative 20 percent net salvage. Mr. Pous concurred in this recommendation. Ms. Mathis recommended a net salvage rate of negative 5 percent for Account 354. 452 This recommendation is based on Commission precedent due to the absence of reliable historical salvage data. 453 Although historical salvage data is available for the period of 1984 through 2010, this account had a low level of retirement during this period. 454 Because of the limited retirement activity, Ms. Mathis stated that a reasonable net salvage rate cannot be calculated from the historical salvage data. 455 For example, annual net salvage rates range from approximately negative 6,000 percent to approximately positive 31,253,400 percent.456 According to Ms. Mathis, such divergent numbers are indicative of the low retirement activity within this account. The negative five percent net salvage value recommended by Ms. Mathis is the current Commission-approved number. The AUs find it difficult to draw any conclusions from the paucity of historical data. Had there been additional historical data, it might have been possible to reach the conclusion urged by Mr. Watson; however, there was not. The ALls recommend that the Commission adopt the negative five percent net salvage value recommended by Staff. 451 ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 66. 452 Staff Ex. 2 (Mathis Direct) at 23. 453 Id. at 23. 454 ETI Ex. 13 (Watson Direct) at DAW-1at66. 455 Staff Ex. 2 (Mathis Direct) at 23. 456 Id. at Appendix C at 2. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 138 PUC DOCKET NO. 39896 (iv) Account 355-Poles and Fixtures The Commission approved net salvage value for this account is a negative 25 percent.457 This account has shown negative salvage since the 1990s, and the most recent ten-year moving averages show negative 33.84 percent net salvage. Although years 2009-2010 reflect positive salvage values, Mr. Watson determined that these values were the product of differences in the timing of the recording of the various transactions associated with the asset retirement, rather than reflecting an actual positive salvage amount. 458 For example, Mr. Watson's net salvage workpapers show a significant level of positive salvage only for the years 2009-2010 in Account 355. 459 This is at odds with the remainder of the net salvage data shown in the workpapers, which is almost exclusively negative net salvage. 460 Accordingly, Mr. Watson gave less weight to the 2009 and 2010 values, but moderated his recommendation compared to the ten-year moving averages, resulting in a recommended net salvage of negative 30 percent. Ms. Mathis concurred. Cities witness Po us disagreed with Mr. Watson's analysis, claiming: ( 1) per book data from the five-year and ten-year moving averages show positive net salvage amounts; (2) authoritative depreciation treatises do not support Mr. Watson's decision to adjust relocation-related transactions out of the analysis; 461 (3) no portion of relocation-related costs can be treated as removal unless that treatment is prescribed by contract with the third-party; and (4) after the correction to his analysis, Mr. Watson changed his methodology to arrive at a negative net salvage recommendation. Mr. Pous recommended an increase in the net salvage values to a negative 15 percent based on the actual historical data of ETI. Cities contend that Mr. Pous was conservative in his recommendation given 457 Cities Ex. 5C (Pous Depreciation Study) at 23. 458 ETI Ex. 13 (Watson Direct) at Ex. DAW-I, p. 66. 459 ETI Ex. 13A (Watson Workpapers CD), Adjusted Data Net Salvage Tab, account 355, lines 130-131, columns I S. 460 ETI Ex. 13A (Watson Workpapers CD), Adjusted Data Net Salvage Tab, account 355, at lines 105-129, columns I - AC. The 2005-2006 data in this workpaper show an obvious example of an accounting adjustment timing difference, wherein the year 2005 shows a $1,867,532 removal cost (row 126, column G), while the immediately following year 2006 shows a large negative removal adjustment of ($1,059,096), (row 127, column G). 461 Relocations involve the situation where the Company is reimbursed by a third party who desires the relocation or replacement of the facilities in question. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 139 PUC DOCKET NO. 39896 the trend in the data. The most recent five-year band of actual data yields a positive two percent net salvage.462 The ALI s agree that the debate regarding this account essentially boils down to whether Mr. Watson's adjustment to remove relocation expense associated with third-party reimbursement from the analysis is appropriate. Although Mr. Pous claims that Mr. Watson's approach is contrary to authoritative guidance, ETI contends that he arrives at that conclusion only by disregarding the guidance in question, as well as Commission precedent. ETI argues that the depreciation text in question squarely supports Mr. Watson's approach: A reimbursed retirement is one for which the company is fully compensated at the time of retirement .... Usually reimbursed retirements should not be included in analysis of property whose investment is recovered through depreciation accruals. 463 Mr. Watson explained at hearing that, in his experience, adjustments to remove relocation expense are standard in depreciation analysis, and to do otherwise would result in a disproportionate impact on reasonably expected ongoing net salvage, caused by a transaction (the relocation) that constitutes a very small portion of the overall assets in question. 464 Mr. Pous stated that all third-party reimbursements for facility relocation performed by the Company have to be deemed as salvage (thereby inflating the salvage portion of the net between removal costs and salvage proceeds) unless a contract between ETI and a third-party explicitly says otherwise. Mr. Watson's approach, however, is squarely supported the Commission's decision in the recent Oncor case, Docket No. 35717, where it was held that these third-party "reimbursements are prepayments for new property being installed."465 The Al.Js find that Mr. Pous' argument is not credible in light of Mr. Watson's treatment of relocations in general. Since Mr. Watson properly removed such relocation expense from the depreciation analysis altogether, those amounts correctly 462 Cities Ex. 5C (Pous Depreciation Study) at 22-25. 463 ETI Ex. 71 (Watson Rebuttal) at 63 (quoting Depreciation Systems, Iowa State Press, 1994, at 16-17). 464 Tr. at 405. 465 ETI Ex. 71 (Watson Rebuttal) at 63. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 140 PUC DOCKET NO. 39896 have no impact on depreciation rates, regardless of how they are allocated between gross salvage proceeds and the cost of installing new facilities. ETI' s evidence and argument support its request. Accordingly, the AUs recommend that the Commission approve a net salvage of negative 30 percent as proposed by Mr. Watson. (v) 356-0verbead Conductors and Devices The Commission approved net salvage value for this account is a negative 20 percent.466 Much as was the case with Account 355, ETI argues that timing differences in reflecting accounting adjustments made the more recent shorter data bands less representative of reasonably expected future net salvage. Mr. Watson's study determined that the longer ten-year moving average for transaction year 2010 showed salvage of negative 33 percent, so Mr. Watson recommended moving to negative 30 percent net salvage for this account.467 Staff witness Mathis adopted the same negative net salvage value. Cities' witness Pous recommended an increase to the net salvage value to a negative 10 percent based on a review of the actual historical data. The actual five-year and ten-year bands yield a positive one percent and a negative 31 percent. Mr. Pous argues that the trend in the data could justify even a less negative value. As with Account 355, the AUs find that ETI's evidence and arguments support its request. Accordingly, the ALl s recommend that the Commission approve a net salvage of negative 30 percent as proposed by Mr. Watson. 466 Cities Ex. SC (Pous Depreciation Study) at 25. 467 ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 66-67. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 141 PUC DOCKET NO. 39896 4. Distribution Plant (a) Lives An asset's useful life is used to determine the remaining life over which the cost will be spread for recovery through depreciation expense.468 The Company's depreciation study addresses 14 distribution accounts included between Accounts 360.2 and 373.2. According to ETI, the life parameters in Mr. Watson's study reflect standard depreciation analysis procedures, including comparison to standard Iowa curves and actuarial analysis, along with the exercise of informed judgment.469 Multiple bands and trends were reviewed and, in general, Mr. Watson's study explained that the dispersion curve chosen for each account is based on examination of the various "placement and experience bands"470 and the characteristics of the underlying asset in each account. The dispersion curve is then chosen that best matches the actual data. 471 Staff disagrees with Mr. Watson's life parameters for three accounts; Cities with five accounts. The parties' various recommendations on the accounts in dispute are shown below: De reciation Plant Lives Account A roved Life ETIPro osal Staff Pro osal Cities Pro osal 361 45 s. S2 65 70 65 s. R3 364 44 38 40 44 365 44 39 40 42 367 40 35 35 45 368 39 29 29 33 369.1 36 26 26 33 468 Id. at 16. 469 Id. at Ex. DAW-I at 37-54. 470 Placement bands look at assets installed in various years and reveal the types of assets in the account over time. Experience bands show accounting transactions associated with the assets over time and reveal trends associated with operational changes and other events. 471 ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 37-54. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE 142 PUC DOCKET NO. 39896 (i) Account 361 - Structures and Improvements Mr. Watson's study depicts the fit between the actual data in the account and the 65 R3 life 472 parameter that he proposed for this account. Mr. Pous agreed with this recommendation. Ms. Mathis stated, however, that a life parameter of 70 R3 is a better visual fit for the 1960-2010 experience band. 473 Considering all the historical mortality data available for this account (the overall experience band), the selected Iowa Curve produces a conformance index (Cl) of 37.53.474 The CI is a measure of closeness of fit, and a higher CI value indicates a closer fit between the two sets of data that are being compared.475 Mr. Watson recommended a life parameter of 65 years based on comparing various slices (bands) of this account's mortality data to the 65 R3 Iowa Curve. 476 However, Staff argues that Mr. Watson's recommended life parameter and Iowa Curve of 65-R3 produces a CI of only 23.61 when measured against the overall (1960-2010) experience band.477 ETI responds that the flaw in Ms. Mathis' position is that she only looks at one band. As the average age of the investment is only 19.22 years, it is inadequate to look at only one band that examines a 50-year period. When shorter bands are also factored in (1970-2010 and 1990-2010), the Company's proposal shows a significantly higher CI, which is indicative of a better fit to the actual data.478 The AL.Ts are persuaded that, in this instance, Ms. Mathis erred by limiting her review to a single band, especially when that band is significantly longer than the average age of the investment 472 Id. at Ex. DAW-1at37. 473 Staff Ex. 2 (Mathis Direct) at 25-26. 474 Id. at 26, Table-5. 475 ETI Ex. 71 (Watson Rebuttal) at 24. 476 ETI Ex. 13 (Watson Direct) at 18, Figure 1. 477 Staff Ex. 2 (Mathis Direct) at 26, Table-5. 478 ETI Ex. 7 I' (Watson Rebuttal) at 24. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 143 PUC DOCKET NO. 39896 at issue. In this case, looking at multiple, shorter bands will give a clearer picture of the average life of the investment at issue. Therefore, the AU s recommend the Commission approve the 65 R3 life parameter Mr. Watson proposes for this account. (ii) Account 364-Poles, Towers, and Fixtures 479 Mr. Watson's study results in his proposing a life parameter of 38 Rl.5. He stated thatthe current plant in service reflects a life (13.97 years on average) that is substantially shorter than his recommendation, and all the bands examined reflect a shorter life than the currently approved 44 years. Mr. Watson testified that his recommendation balances these facts with the additional fact that ETI is currently using Penta and CCA-treated poles (as opposed to creosote treated poles), for which a longer life is expected. Ms. Mathis (40 Rl) and Mr. Pous (44 Ll) both proposed different life parameters than Mr. Watson. Ms. Mathis stated that her proposed life parameter is a better visual and mathematical fit for the single experience band (1959-2010) she considered. 480 Mr. Watson responded to this argument, stating that the mathematical computer fitting emphasized by Ms. Mathis is too limited an approach, because there is too little information provided at the tail of the curve to rely on computer fitting in this instance. Mr. Watson indicated that his proposed life parameter shows a better fit over the full range of placement and experience bands applicable to this account. 481 Mr. Pous recommended that the expected service life remain at 44 years based on actuarial analysis and advances made by the industry and ETI in treating and preserving poles. 482 Mr. Pous also noted that "absent identifiable and supportable specific problems, the industry is not experiencing shorter lives for poles and neither should ETI." 483 He stated that selection of different types of poles and different treatments by other utilities have their engineers expecting lives between 479 ETI Ex. 13 (Watson Direct) at Ex. DAW-I at 41. 480 Staff Ex. 2 (Mathis Direct) at 28-29. 481 ETI Ex. 71 (Watson Rebuttal) at 29-31. 482 Cities Ex. SC (Pous Depreciation Study) at 35-36. 483 Id. at 37. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE144 PUC DOCKET NO. 39896 484 50 and 70 years. According to Mr. Pous, it is simply not realistic to believe or assume that ETI would operate now or in the future in a manner that its poles would only last two-thirds the life 485 expectance being achieved by others. Mr. Watson responded that the increased life span urged by Mr. Pous based on his general discussion of varieties of poles with longer lives is not verifiable, not consistent with the Company-specific data or the specific experience of its distribution personnel, and is plainly exaggerated. 486 The AU s reviewed the evidence and arguments of the parties with respect to this issue and were most persuaded by the Cis that resulted from the recommendations of Staff and ETI. Considering all the historical mortality data available for ~his account (the overall experience band), Staff's selected Iowa Curve produces a CI of 41..44, while ETI's produces a CI of only 20.66 when measured against the overall (1958 - 2010) experience band.487 The AUs recommend that the Commission adopt Staff's proposal of 40 Rl. (iii) Account 365 - Overhead Conductors and Devices 488 The Commission approved average service life is 44 years. All parties propose a change to this life parameter. Mr. Watson proposed a life parameter of 39 R0.5, Ms. Mathis proposes a life parameter of 40 R0.5, and Mr. Pous proposed a life parameter of 42 S.-5. Mr. Watson noted that his analysis took into account the fact that the currently authorized life is longer than the history would support, and that the young average age of the current plant in service (12.15) points toward placing more weight on recent bands for life selection. He also noted that ETI' s movement toward re-conductoring lines supports the conclusion that lives in this account will be shorter. 484 Id. 485 Id. at 36. 486 ETI Ex. 71 (Watson Rebuttal) at 28-29. 487 Staff Ex. 2 (Mathis Direct) at 29, Table-6. 488 Cities Ex. SC (Pous Depreciation Study) at 38. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE 145 PUC DOCKET NO. 39896 Ms. Mathis indicated that her recommendation is based on comparing the account's historical mortality data for the period of 1958 through 2010 to the 40 R0.5 Iowa Curve.489 Considering all the historical mortality data available for this account (the overall experience band), the selected Iowa Curve produces a CI of 29.63.490 Mr. Watson countered that Ms. Mathis used the wrong curve to represent the Company's proposal in her calculations. He stated that when her analysis is corrected to make the proper comparison, ETI's proposal has a higher CI (and thus a better fit) across all experience bands save one. 491 Mr. Pous testified that his life parameter best matches the actuarial analysis taking into account the unusually high level of retirement activity recorded in the first 0.5 year of age. As Mr. Pous noted, "the highest retirement ratio for this investment in the first 23 years occurred at age 0.5 years, for brand new assets. While such events can and have occurred associated with utility plant, it is not the type of event that is reasonably expected to repeat itself in future periods as different equipment it purchases if it was an equipment problem, or different installation processes are employed if the early retirement were due to installation issues."492 Mr. Pous criticized Mr. Watson's recommendation on several grounds: (1) it is not consistent with expected lives reported by ETI personnel; (2) it did not account for anomalies and/or unusual activity in the retirement data; (3) the major re-conductoring activity shown in the account should not be expected to continue; and (4) the life-curve combination chosen by Mr. Watson is not long enough to match 493 the actual data. Mr. Watson took issue with Mr. Pous. He stated that Mr. Pous simply misread the data Mr. Watson argued that Exhibit DAW-R-1 to his rebuttal testimony shows that retirements are decreasing. 494 Mr. Watson believes that his proposed life parameter is a better fit to the actual data. 489 Staff Ex. 2 (Mathis Direct) at 30. 490 Id. at 31, Table-7. 491 ETI Ex. 71 (Watson Rebuttal) at 36. 492 Cities Ex. 5C (Pous Depreciation Study) at 38-39. 493 Id. at 38-41. 494 ETI Ex.71 (Watson Rebuttal) at 32-33. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 146 PUC DOCKET NO. 39896 The very small amount of plant that may not last until the tail of the curve used by Mr. Watson does not alter this conclusion.495 Finally, ETI argues that Mr. Pous provides no persuasive basis for second guessing the opinion of Company personnel regarding re-conductoring. The AI.Js are persuaded by ETI's evidence and argument. It does appear that Ms. Mathis used the wrong curve in her calculations. If corrected, Mr. Watson's proposal renders the higher CI. Mr. Pous' arguments fair no better. To the Al.Js' eye, Mr. Pous did misread the data, and the conclusions drawn by Mr. Pous are simply inaccurate. The ALl s recommend that the Commission adopt ETI's proposed life parameter of 39 R0.5. (iv) Account 367 - Underground Conductors and Devices The Commission approved average service life is 40 years. 496 Mr. Watson's life parameter for this account (35 Rl.5) is based on h.is review of the various placement and experience bands, as well as the characteristics and longevity of the conductors in place in the ETI system and the retirement patterns that are unique to underground conductor performance and the locations where it is buried. 497 Ms. Mathis agreed with Mr. Watson on this account. Cities propose a significantly longer life (45 S-0.5). Mr. Pous stated that Mr. Watson's and Ms. Mathis' recommendations do not account for the increased durability of newer types of conductor, and that the actuarial analysis should focus on more recent data that he believes is more consistent with the newer conductors. 498 Mr. Watson testified that Mr. Pous' recommendation should be rejected for a variety of reasons. The Southern California Edison-based opinions regarding longer life for the conductor, relied on by Mr. Pous, relate to plant installed less than ten years ago. Therefore, based on his own theory, much of the investment in question in this account is still the older, shorter-lived variety, and his recommendations are premature. Moreover, Mr. Watson's plotting of the dispersion curves show 495 Id. at 32, 33-35. 496 Cities Ex. 5C (Pous Depreciation Study) at 41. 497 ETI Ex. 13 (Watson Direct) at Ex. DAW-1, p. 45. 498 Cities Ex. 5C (Pous Depreciation Study) at 41-44. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 147 PUC DOCKET NO. 39896 that his is a better fit than that of Mr. Pous. fu this instance, Mr. Pous' analysis, relying only on the shortest band, failed to pick up the older investment that constitutes almost 80 percent of the surviving investment.499 It appears that Mr. Pous, in relying on the shortest band, did fail to take into account investment that comprises almost 80 percent of the surviving investment in this account. That is a significant flaw in his analysis. Similarly, his reliance on the Southern California Edison-based opinions relate to newer plant, which again calls his analysis into question in the present circumstances. The Al.J s recommend that the Commission approve ETI' s recommended service life of 35 Rl.5. (v) Account 368 - Line Transformers The Commission approved anticipated service life is 39 years. 500 Mr. Watson proposed a service life of 29 Ll ,501 with which Ms. Mathis agreed. Mr. Watson stated that this is consistent with the data showing decreasing lives for these assets, the expected lives per Company personnel, and the fact that transformers are junked or sold rather than repaired. 502 Mr. Pous recommended that the expected service life be decreased to 33 years, representing a 15 percent reduction in the anticipated service life. Mr. Pous stated that his analysis is based on actuarial analyses and the Company's addition of approximately $80 million of pad mounted transformers since the last case, when the Commission approved a 39-year anticipated average service life. According to Mr. Pous, ETI personnel have stated that pole mounted transformers have a life of between 25 and 35 years. However, pad mounted transformers are expected to last up to 40 years by the same Company personnel. Given the sizable investment since the last case in the pad mounted transformers with a longer expected service life, a decrease in the anticipated service life of 499 ETI Ex. 71 (Watson Rebuttal) at 40. 500 Cities Ex. SC (Pous Depreciation Study) at 44. 501 ETI Ex. 13 (Watson Direct) at Ex DAW-I at 50. 502 Id. at 47. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 148 PUC DOCKET NO. 39896 greater than 15 percent is not warranted, according to Mr. Pous. Moreover, Mr. Pous stated his analysis uncovered abnormally high retirement ratios in the 21.5 to 22.5 year age brackets indicative of one-time events such as the ice storm or changes in accounting systems. As such, Mr. Pous performed his curve fitting analysis recognizing the unusually high retirement activity between years 21.5 and 22.5 rather than emphasizing such unusual activity as Mr. Watson did for his proposal to reduce service life by 26 percent. 503 Mr. Watson recommended a decline in average service life from a 39-year anticipated service life to a 29-year anticipated service life citing the high occurrence of lightning in the ETI service area. 504 However, Mr. Pous noted that the effects of lightning in ETI' s service area would have been present in ETI's last base rate case when a 39-year anticipated service life was approved by the Commission. Both Mr. Watson and Mr. Pous recognized that the pad mounted transformers are not subject to the same forces of retirement like weather, lightning, and animal disturbances. 505 However, Mr. Watson did not realistically factor ETI's relative increased investment in pad mounted transformers into his analysis. Moreover, when performing his curve fitting analysis, Mr. Watson neither analyzed nor adjusted for the abnormal unusual retirement ratios between years 21.5 and 22.5. 506 Instead, Mr. Watson attempted to select a life analysis that anticipates a high level of retirement within that time period in the future. sm Cities argue that, by failing to recognize the sizable new investment in pad mounted transformers and failing to consider the unusual retirement ratios, Mr. Watson proposed an average service life that is lower than the bottom end of the range of life estimates of Company personnel for pad mounted transformers. Moreover, Mr. Watson's proposal does not even reach the midpoint of life estimates expected by Company personnel for pole mounted transformers. 503 Cities Ex. 5C (Pous Depreciation Study) at 45. 504 ETI Ex. 13 (Watson Direct) at Ex DAW-1 at 50. 505 Id. 506 Cities Ex. 5C (Pous Depreciation Study) at 47. 507 ETIEx.13 (WatsonDirect)atExDAW-1 at50-51. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE149 PUC DOCKET NO. 39896 The arguments and evidence advanced by Cities witness Pous are persuasive to the ALl s. Mr. Watson's contention regarding the occurrences of lightening in the ETI service area was equally applicable at the time the existing approved rate was set, and is, therefore, of little value in this proceeding. Further, Mr. Watson's failure to analyze the abnormal retirement ratios between years 21.5 and 22.5 also argues against his analysis. The ALls recommend that the Commission adopt Mr. Pous' proposed life of 33 L0.5. (vi) Account 369.1-0verhead Services The Commission previously approved anticipated service life for this account is 36 years.508 Mr. Watson's analysis of this account shows that overhead assets have retired earlier and have been replaced more frequently than is consistent with the existing 36 S4 life. The average age of current investment is 10.12 years. Consistent with this data and his review of various curves and placement and experience bands, he recommended shortening the life to 26 L4. Ms. Mathis agrees with this proposal. 509 Mr. Pous recommended that the expected service life be shortened to 33 years based on the lack of Company historical data and based on comparative utility experience including recent studies by Mr. Watson, where he proposed significantly longer average service lives. Mr. Pous testified that an evaluation of the actual data casts serious doubt about the reliability of the data for depreciation purposes. ETI does not have any records of services in this subaccount surviving past 1978. Mr. Pous stated that his recommended 33-year life expectancy for this sub-account is still far shorter than industry expectations, but is consistent with the depreciation study recently conducted for EGSL where the depreciation expert hired by EGSL recommended a 33-year life. 510 ETI argues that Mr. Pous apparently made no attempt to perform any curve fitting regarding this account, as none appears in his study; in the absence of performing this essential analysis, he 508 Cities Ex. SC (Pous Depreciation Study) at 48. 509 ETI Ex. 13 (Watson Direct) at Ex. DAW-1at49. 510 Cities Ex. SC (Pous Depreciation Study) at 48-49. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE150 PUC DOCKET NO. 39896 settles for again casting doubt on the reliability of Company accounting data. ETI contends that, in reality, Mr. Pous appears to present no recommendation for this account based on evaluation of any of the accounting data that actually depicts the past and current characteristics of the assets. 511 ETI argues that its recommended life is clearly supported by the Company-specific data, graphically depicted in Mr. Watson's rebuttal testimony, while Mr. Pous' suggested life parameter is not even close, and is based on unsupported speculation. 512 Although the evidence on this issue is sparse, the ALls ultimately are persuaded that ETI's (and Staffs) position is more reasonable. Accordingly, the AUs recommend the Commission adopt ETI' s proposed 26 L4 life span. (b) Net Salvage Value Staff disagrees with Mr. Watson's recommendations for five of the distribution accounts, and Mr. Pous disagrees regarding two of the accounts. The parties' positions on distribution net salvage values in dispute are set out immediately below: Distribution Plant Net Salva2e Account Approved Rate ETI Proposal Staff Proposal Cities Proposal 361 -5% -10% -5% -10% 362 +15% -20% -10% 0% 365 +10% -7% -7% 0% 368 0% 0% -5% 0% 369.1 -10% -5% -10% -5% 369.2 -10% -5% -10% -5% (i) Account 361 - Structures and Improvements The existing net salvage value for this account is negative five percent, which is the value proposed by Staff. Mr. Watson and Mr. Pous, on the other hand, proposed a salvage value of negative 10 percent. 511 Id. at 48-50. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 151 PUC'DOCKET NO. 39896 Mr. Watson's recommendation is based on the most recent five-year and ten-year net salvage ratios, which are negative 9.70 percent and negative 36.70 percent, respectively. Ms. Mathis' recommendation is based on analysis of historical salvage data for the period of 1984 through 2010. Specifically, the two-year moving average median for the same period produces a net salvage rate of negative 5.87 percent, which is very close to the currently approved net salvage rate for this account. 513 Moreover, the one-year, three-year, four-year, five-year, six-year, and seven-year moving average medians of negative 6.95 percent, negative 5.11 percent, negative 3.64 percent, negative 1.90 percent, negative 4.57 percent, and negative 7.24 percent, respectively, support this recommendation. Additionally, this account contains a few significant outliers, such as negative 655.91 percent in 2002 and negative 322.55 percent in 2005. 514 Ms. Mathis' use of the median average eliminates the skewing effect of these outlying values. As discussed in Section VII.C.l, the use of the median is the most appropriate methodology. For this reason, the AUs recommend the Commission approve Staffs proposed negative 5 percent net salvage value. (ii) Account 362 - Station Equipment The existing net salvage value of this account is positive 15 percent. Mr. Watson proposed that it be changed to negative 20 percent, Staff proposes it be changed to negative 10 percent, and Cities propose it be changed to zero. Mr. Watson's study shows that the most recent five-year and ten-year net salvage ratios are negative 22.10 percent and negative 43.55 percent, respectively. He recommended negative 20 percent net salvage based on the Company's experience. 515 512 ETI Ex. 71 (Watson Rebuttal) at 46-48. 513 Staff Ex. 2 (Mathis Direct) at 27. 514 Id. at Appendix C at 4. 515 ETI Ex. 13 (Watson Direct) at Ex. DAW-1at68. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE152 PUC DOCKET NO. 39896 Ms. Mathis' recommendation is based on analysis of historical salvage data for the period of 1984 through 2010. Specifically, the recommendation is supported by the two-year moving average median for the same period of negative 12.23 percent.516 Moreover, the one-year, three-year, five-year, six-year, seven-year, and eight-year moving average medians of negative 11.07 percent, negative 14.16 percent, negative 7.62 percent, negative 8.19 percent, negative 11.75 percent, and negative 14.15 percent, respectively, support her recommendation. 517 Mr. Pous' recommendation is based on what he characterizes as the Company's actual, unadjusted, experience; recognition of the type of investment in the account; recognition of significant value of scrap copper; investigation of retirement mix compared to investment mix over the past ten years; and recognition of industry values. 518 According to Mr. Pous, given the significant increase in the value of copper, the retirement of a transformer could be expected to significantly influence the net salvage value for this account. Mr. Pous' recommendation is the outlier among the three before the ALls, and the ALls are not convinced that the reasons put forth by Mr. Pous in support of his position are sufficient to carry the day. The real argument here is between ETI and Staff, which centers on the use of the median (Staff) and the mean (ETI). As discussed in Section VII.C.l, the use of the median is the most appropriate methodology. For this reason, the ALls recommend the Commission approve Staff's proposed negative 10 percent net salvage value. (iii) Account 365 - Overhead Conductors and Devices The current net salvage value for this account is positive 10 percent. 519 ETI and Staff recommend changing it to negative seven percent, and Cities recommend changing it to zero. 516 Staff Ex. 2 (Mathis Direct) at 27. 511 Id. at Appendix C at 4-5. 518 Cities Ex. SC (Pous Depreciation Study) at 26. 519 Id. at 28. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 153 PUC DOCKET NO. 39896 Mr. Pous recommended a reduction in the current net salvage values to zero based on review of the actual historical data and the relative mix of the investment recorded in this account. Mr. Pous noted that $40 million of investment recorded in this account is associated with clearing rights of way, which will not likely be retired or incur cost of removal or gross salvage. Another $40 million is associated with investment in copper conductors, which has escalated in demand in recent years and should result in positive net salvage. 520 Mr. Watson corrected his analysis and recognized that timing differences between the recording of accounting adjustments related to net salvage (i.e., salvage and removal costs for a particular transaction were not recorded at the same time) made one of the recent years less representative of reasonably expected ongoing net salvage levels. He focused, therefore, on longer period averages and recommends negative seven percent net salvage consistent with the most recent ten-year ratios. 521 Mr. Watson explained that his adjustments removed relocation activity altogether from this account because it is not characteristic of the vast majority of retirements and because, if the adjustment is not made, it will shorten and skew the life analysis. Further, Mr. Watson stated that Mr. Pous' claims regarding the impact of copper prices ignore those prices' future volatility and are not supported by any analysis or quantification specific to these accounts. Mr. Watson indicated that his recommendations are based on the most clear and reliable source - Company-specific accounting data - not "selective comparisons of industry norms," as alleged by Mr. Pous. 522 The AUs find Mr. Watson's explanations of the rationale behind his analysis to be both credible and convincing. Accordingly, the AUs recommend the Commission adopt ETI's requested negative 7 percent net salvage value. 520 Id. at 28-29. 521 ET1Ex.13(WatsonDirect)atEx.DAW-l at69. 522 ETI Ex. 71 (Watson Rebuttal) at 68-69. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 154 PUC DOCKET NO. 39896 (iv) Account 368 - Line Transformers The existing net salvage value for this account is zero, which both Mr. Watson and Mr. Pous recommended be retained. Ms. Mathis, on the other hand, argued that the net salvage value should be changed to negative five percent. The argument here is whether the median or the mean best represents the appropriate net salvage value. ETI argues for the mean, and Staff argues for the median. As discussed in Section VIl.C.1, the use of the median is the most appropriate methodology. For this reason, the Al.J s recommend the Commission approve Staff's proposed negative five percent net salvage value. (v) Account 369.1-0verhead Services The existing net salvage value for this account is negative 10 percent, which Staff recommends be retained. Mr. Watson and Mr. Pous argue in favor of a change to negative 5 percent net salvage value. The argument here is whether the median or the mean best represents the appropriate net salvage value. ETI argues for the mean, and Staff argues for the median. As discussed in Section VIl.C.l, the use of the median is the most appropriate methodology. For this reason, the Al.J s recommend the Commission approve Staffs proposed negative 10 percent net salvage value. (vi) Account 369.2- Underground Services ETI began specifically charging salvage and removal cost to this account just in the last two years, producing a five-year net salvage ratio of negative 15. 75 percent. Mr. Watson recommended moving from the current negative 10 percent to negative five percent net salvage. 523 Mr. Pous 523 ETI Ex. 13 (Watson Direct) at Ex. DA W-1 at 70. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGElSS PUC DOCKET NO. 39896 agreed. Because of the limited available data, Ms. Mathis recommended retaining the existing negative 10 percent net salvage. 524 The AUs agree with Staff that because of the limited retirement activity, a reasonable net salvage rate cannot be calculated from the historical salvage data. Accordingly, the AUs recommend the Commission adopt the negative 10 percent net salvage value proposed by Staff. S. General Plant General plant includes some accounts that are subject to depreciation, and some that are subject to amortization. ETI proposes to adopt "Vintage Group Amortization," consistent with FERC Rule AR-15 for Accounts 391-397.1 and Account 398. This approach, approved by both the FERC and the Commission (Docket No. 38339), does not affect the annual level of expense, but provides for timely retirement of assets and simplifies accounting for general property. 525 Ms. Mathis concurred in the Company's proposal to adopt Vintage Group Amortization and with its recommendations for lives, amortization periods, and net salvage. 526 The increase in expense for general plant proposed by ETI is due to the need to reduce the deficit in the general plant reserve caused by inadequate account level rates in the past. 527 This is a matter of debate among the parties, as discussed in more detail below. (a) Account 390 - Structures and Improvements (Life Parameter) Based on his analysis of the data in comparison to various potential dispersion curves, Mr. Watson recommended an increase in the life of this account to 45 R2. 528 Ms. Mathis agreed with this life. Mr. Pous proposed a significantly longer life (54 S0.5) and claimed that Mr. Watson did 524 Staff Ex. 2 (Mathis Direct) at 34. 525 ETI Ex. 13 (Watson Direct) at Ex. DAW-1at2-3. 526 Staff Ex. 2 (Mathis Direct) at 35-37. 527 ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2-3. 528 Id. at Ex. DAW-1 at 56. SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE156 PUC DOCKET NO. 39896 not adequately investigate the data and investments in this account. Mr. Pous concluded that "superstructures and roadways" are a significant element in the account which can be expected to have a long life. 529 ETI contends that Mr. Pous' analysis is incorrect. First, as confirmed by his workpapers, Mr. Watson conducted an analysis of five bands, not a single band as alleged by Mr. Pous. Furthermore, Mr. Pous' argument regarding long lives, based on the idea that the investment dates back to 1927, is contrary to the actual data showing a minute amount of old investment (0.02 percent of the account) dating back only to 1939. The average age of investment in the account, however, is only 15.87 years. Mr. Watson explained that the actual data shows no investment has achieved a life of 85 years, as alleged by Cities. 530 The AI.Js believe that the actuarial analysis and curve fitting shown in Mr. Watson's direct and rebuttal testimony demonstrate a more reasonable approach, as recognized by Staff witness Mathis. Therefore, the AI.Js recommend the Commission adopt the 45 R2 life parameter recommended by ETI. (b) Account 390-Structures and Improvements (Net Salvage Value) Account 390 is a depreciable account for structures and improvements. Though the current authorized net salvage is zero, Mr. Watson recommended a negative five percent net salvage value, and Staff agrees with this recommendation. Mr. Pous recommended a positive 15 percent net salvage value. Mr. Watson based his recommendation on the most recent five-year and ten-year ratios, which are negative 1.51 percent and negative 34.27 percent. 531 Mr. Pous disagreed, arguing that: (1) Mr. Watson's data adjustments present an incorrect picture of the salvage history; and 529 Cities Ex. SC (Pous Depreciation Study) at 51. 530 ETI Ex. 71 (Watson Rebuttal) at 49. 531 ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 73. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE 157 PUC DOCKET NO. 39896 (2) Mr. Watson failed to account for the difference in net salvage values between the retirements of leaseholds, versus Company-owned facilities, which should not produce negative salvage. 532 According to ETI, Mr. Po us' argument that retirement and sales of buildings will result in positive net salvage is not backed up by the Company-specific data for this account. Such data shows that negative net salvage has occurred in every period of the most recent ten-year moving average. Averages of six years or longer range from negative 4.56 percent to negative 34.27 percent. 533 ETI also argues that Mr. Pous' attempt to use sales of facilities as an element of depreciation analysis is contrary to Commission precedent regarding building sales 'and that his opinion is contrary to the facts that such sales are unique circumstances that do not reasonably represent the ongoing year-to-year retirement activity that should form the basis of depreciation analysis. The ALls find that Mr. Pous' arguments are not supported by the facts and that Mr. Watson's explanations are the more credible. Accordingly, the ALls recommend the Commission adopt ETI's proposed negative five percent net salvage value for this account. (c) General Plant Reserve Deficiency A $21.3 million deficit has developed over time in the reserve for the accounts that ETI proposes should be converted to General Plant Amortization. This deficit, or under-recovery, has occurred because assets have been retired more quickly than can be addressed by the existing amortization rate. ETI, therefore, proposes a $2.1 million annual expense level to recover the deficit over ten years. 534 Ms. Mathis recommended that the amortization of the reserve deficiency be rejected and that the deficit be recovered through application of the remaining life method to the individual accounts where the deficit occurred. 535 532 Cities Ex. 5C (Pous Depreciation Study) at 3 L 533 ETI Ex. 71 (Watson Rebuttal) at 73-74. 534 ETI Ex. 13 (Watson Direct) at Ex. DAW-2 at 2, App. A-2 at 1-2. 535 Staff Ex. 2 (Mathis Direct) at 38. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 158 PUC DOCKET NO. 39896 ETI argues that although Ms. Mathis' recommendation could theoretically allow recovery, her calculation of the amortization for the accounts that created the deficit is erroneous and insufficient to carry out her proposed concept for recovery. During her cross examination, Ms. Mathis agreed that she had intended to take the elements of the remaining life calculation 536 method exclusively from Mr. Watson's depreciation study. ETI contends that she failed to pull the correct values from Mr. Watson's study and her numbers did not match the corresponding entries from Mr. Watson's study. 537 For example, Ms. Mathis affirmed that her remaining life calculations were intended to allow recovery of the remaining investment in general plant account 391.2. The 538 remaining investment she provided for was $10.9 million of an original cost of $21.7 million. The actual remaining investment in the account, however, as shown in the data she purported to rely on, was a credit balance of negative $4.4 million, meaning that not only the original cost, but $4.4 million additional investment remained unrecovered. 539 Ms. Mathis had no explanation for the difference. In fact, it appears that she erroneously substituted the theoretical reserve for the account in Mr. Watson's study ($10.789 million) as the actual book reserve, resulting in an erroneous 540 calculation of the amount yet to be recovered. Mr. Watson's rebuttal points out the errors in the calculation and provides an exhibit to properly reflect the remaining life approach that Ms. Mathis intended. 541 However, Mr. Watson's rebuttal also explained the reasons that the Company's approach is better. By using a ten-year amortization period for the deficit, ETI lowers the annual amount of the expense in rates to $2.1 million. Once Ms. Mathis' calculation is corrected, because the remaining lives through which the asset value is recovered are so short, 'her remaining life approach increases the annual expense of amortization to $5.8 million. Given the significant level of expense involved, ETI personnel had asked Mr. Watson to moderate the remaining life approach in this instance by 536 Tr. at 1752-1753. 537 Tr. at 1746-1759. 538 Tr. at 1754; Staff Ex. 2 (Mathis Direct) at Ex. JLM-2 at 4. 539 Tr. at 1755. 540 Tr. at 1759-1761. 541 ETI Ex. 71 (Watson Rebuttal) at 84, Ex. DAW-R-5. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 159 PUC DOCKET NO. 39896 using a ten-year amortization period that was consistent with the approach used by another affiliate within the Entergy system. Moreover, although Ms. Mathis purports to rely on the Commission's decision in Docket No. 38339 in support of her proposal, that case includes no discussion of rejecting the proposal on general plant that Mr. Watson makes here. 542 The AUs have reviewed the evidence cited by both parties and the testimony offered in support of their respective positions. It is clear to the AUs that Ms. Mathis inadvertently did exactly what ETI alleges - she got numbers confused and, in so doing, confused her analysis. The AUs find that ETI' s proposed $2.1 million annual expense level to recover the deficit over ten years be approved by the Commission. (d) Amortization Period for Account 391.2-Computer Equipment Mr. Pons challenged the amortization period for this account, contending, contrary to Staff and Mr. Watson, that the Company's proposal to amortize general plant using ..Vintage Group Amortization" is not consistent with FERC pronouncement AR-15. ETI argues that Mr. Pous' critique is wrong because the five-year life of which Mr. Pons complains is based on standard life analysis. The life has nothing to do with AR-15, which does not determine such matters. Mr. Watson's study clearly explains that he based the life parameter on standard actuarial analysis. 543 According to ETI, Mr. Pons' own recommendation points out the fallacy of his arguments about AR-15. He recommended a one-year increase in the amortization, which does not match the previous period of depreciation for this account, or the previous depreciation rate, despite that being the supposed flaw in Mr. Watson's approach. 544 Mr. Watson explained that the use of AR-15 does not involve any independent tinkering with the life of the asset account because the AR-15 process 542 Id. at 80-81. 543 ETI Ex. 13 (Watson Direct) at Ex. DAW-1at58. 544 Cities Ex. 5 (Pous Direct) at 36. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 160 PUC DOCKET NO. 39896 "provides for the amortization of general plant over the same life as recommended," based on 545 standard life analysis, which Mr. Watson's study recognized. The ALls are persuaded by ETI's arguments on this point. FERC pronouncement AR-15 requires amortization over the same life as recommended based on standard life analysis. Mr. Watson's study employed standard life analysis to ascertain the recommended five-year life. The ALls therefore recommend the Commission adopt the five-year life proposed by ETI. 6. Fully Accrued Depreciation Mr. Pous claimed that the Company has failed to conform its Commission-authorized depreciation rates when it stops accruing depreciation on accounts and sub-accounts that are fully accrued. He testified that the Company must continue to depreciate such accounts, despite the fact that this policy would mandate that the Company intentionally create negative depreciation amounts that do not relate to the existence of any depreciable asset still in existence. Mr. Pous testified that neither standard depreciation definitions nor GAAP or National Association of Regulatory Utility Commissioners (NARUC) depreciation guidance support the Company's action. 546 The impact of Mr. Pous' recommendation is to impute an additional $6,447,731 depreciation amount to reduce rate base and amortize that credit over four years, with an associated revenue requirement reduction of 547 $1,611,933. ETI argues that Mr. Pous pointed to no instance in which his theory has been adopted by the Commission, or any other regulatory body. Other regulators within the Entergy system have rejected his position. 548 The RRC, which sets gas utility rates under essentially the same regulatory framework as PURA, has rejected Mr. Pous' position on three separate occasions. 549 ETI contends that Mr. Pous' suggestion violates GAAP, which requires that once an asset's service value (original 545 ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2. 546 Cities Ex. 5 (Pous Direct) at 39-45. 547 Id. at 45. 548 ETI Ex. 46 (Considine Rebuttal) at 45-46. 549 ETI Ex. 71 (Watson Rebuttal) at 81, n. 61; ETI Ex. 46 (Considine Rebuttal) at Ex. MPC-R-11. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 161 PUC DOCKET NO. 39896 cost less net salvage) has been fully amortized through the application of the most recently approved depreciation rates, there is no further service value to be recognized. This has been ETI' s practice as long as ETI regulatory accounting witness Considine has been aware. Furthermore, ETI suspends depreciation only so long as the account is fully amortized. Once additional activity hits the account, depreciation will begin again under the Company's automated systems. 550 ETI also argues that Mr. Pous' retroactive approach is unreasonably selective. He would reach back into recoveries under existing rates to reclaim revenues associated with the depreciation expense that relates to the fully accrued accounts. According to ETI, Mr. Pous takes no notice of the depreciation taken on new assets that are not included in rate base or recovered through depreciation expense under existing rates. ETI witness Considine notes that Mr. Pous has essentially formulated a one-sided exact recovery mechanism for depreciation expense that is completely unique in the annals of base rates. 551 According to ETI, Mr. Pous also ignores that the remaining life depreciation method already addresses any over- or under-accrual of depreciation expense. As depreciation rates and the remaining life are adjusted over time, any over (under) recovery will be carried forward and the net (if any) of the original investment less any accumulated reserve will begin to be recovered under the new and future rate structures. This is the basic concept of remaining life depreciation rates. Thus, 552 ETI contends that no further actions or adjustments are appropriate. The AUs find that Mr. Pous' recommendation has previously been rejected, by other regulatory bodies. There is nothing in the arguments advanced by Cities that changes that fact. Accordingly, the AUs recommend the Commission reject Cities' proposal. 550 ETI Ex. 46 (Considine Rebuttal) at 44-45, 47. 551 Id. at 43, 45. 552 ETI Ex. 71 (Watson Rebuttal) at 78. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 162 PUC DOCKET NO. 39896 7. Other Depreciation Issues - Accumulated Provision for Depreciation ETI proposes to amortize the $21 million general plant deficiency over ten years. Both the Cities and Staff agree with and use the accumulated depreciation reserve amounts per account from Mr. Watson's study. 553 TIEC witness Pollock, in arguing against amortization of the amortized general plant reserve deficiency, testified that this reserve deficiency should instead be simply reallocated to other depreciable general plant accounts that have depreciation surplus. 554 Mr. Pollock discussed transferring the depreciation reserve between the amortizable and depreciable general plant accounts. He failed to show, however, how the reserve reallocation would be computed and provided no workpapers to substantiate his analysis. ETI argues that without a verifiable basis for the computations, his recommendations to recompute general plant depreciation accruals should be rejected. ETI also argues that Mr. Pollock's testimony shows that he has reallocated the amortizable general plant deficiency from the amortized general plant accounts to the depreciable general plant accounts. The depreciable plant accounts have shorter remaining lives than the ten-year amortization of the deficiency proposed by ETI. 555 ETI contends that common sense dictates that transferring dollars from an account with a relatively longer remaining life to one with a shorter life will yield a higher annual depreciation or amortization expense, yet Mr. Pollock somehow takes this step and still arrives at a lower level of expense. According to ETI, Mr. Pollock's methodology has the effect of "amortizing the difference between the book and theoretical reserve over a time period that is significantly shorter than the average remaining life of the assets within this function." 556 ETI asserts that such an adjustment to 553 Id. at 77. 554 TIEC Ex. 1 (Pollock Direct) at 38-39. 555 ETI Ex. 13 (Watson Rebuttal) at Ex. DAW-l, App. A-1at4. 556 ETI Ex. 71 (Watson Rebuttal) at 75. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 163 PUC DOCKET NO. 39896 depreciation and amortization expense was rejected by the Commission in the CenterPoint rate case, and it should be rejected here. 557 TIEC argues that it does not propose any amortization of any accounts. Rather, TIEC states that it is proposing a more efficient method for ETI to cure its deficits. Because ETI retired equipment prior to the end of the assumed life of those assets, there is approximately a $21,300,000 deficiency in general plant accounts. ETI seeks to amortize the deficiency over ten years so that the book reserve will "catch-up" with the theoretical depreciation reserve for the deficient reserve. TIEC contends that its position is that the catch-up adjustment is not necessary. 558 The ALJs have reviewed the evidence and arguments advanced by the parties and find that those of ETI are more persuasive. Accordingly, the ALJs recommend the Commission reject TIEC' s recommendation. D. Labor Costs 1. Payroll and Related Adjustments A number of parties suggest various adjustments to ETI' s proposed payroll and related costs. In the application, ETI' s Test Year payroll costs were adjusted downward by $957 ,695 to reflect a decrease in the employee headcount levels at ETI during the Test Year. At the same time, payroll costs were increased in the amount of $1, 105,871 to account for employee pay raises. The net result was that ETI's Test Year payroll expense was adjusted upward by $148,176. Similar calculations were made for ESI employees, resulting in a net upward adjustment for ESI payroll expenses of $852,493. Thus, ETI requested an upward adjustment of $1,000,669 ($148,176 plus $852,493) for ETI and ESI payroll expenses. 559 557 Id. at 75-76. 558 TIEC Ex. 1 (Pollock Direct) at 37. 559 ETI Ex. 8 (Considine Direct) at 24-25; 3 at Sched. A-3 and WP/P AJ22. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 164 PUC DOCKET NO. 39896 Cities oppose one part of these proposed adjustments. As noted above, ETI is proposing an upward adjustment to account for pay raises given to ETI and ESI employees. One set of those raises was given to employees in early August 2011, one month after the end of the Test Year. Another set of raises was given to employees in April 2012, roughly nine months after the end of the Test Year. Cities witness Garrett testified that it is acceptable to make an adjustment for the raises made in August 2011 because they occurred shortly after the end of the Test Year. However, he stated that it is unreasonable to include an adjustment for the raises given in April 2012. He believes that any increase in costs due to the April 2012 pay raises might be offset by changes in productivity and the overall workforce that may occur during the same time period, such as the replacement of higher- paid workers who retire with new, lower paid employees. 560 Thus, Cities propose an adjustment that would reverse ETI's proposed increase for the April 2012 pay raises thereby reducing payroll expense by $1,185,811. 561 No other party makes a similar challenge to the April 2012 pay raise. With regard to the adjustments proposed by ETI, Staff witness Givens accepted the adjustments for headcount changes and the pay raises, but recommended a further downward adjustment of $778,034 to account for a further decrease in ETI employee headcount levels from 678 at Test Year-end to 660 as of February 2012. She also recommended an upward adjustment of $158,589 to account for an increase in ESI employee headcount levels from 3,055 to 3,089 as of December 2011. 562 Ms. Givens also recommended that, in addition to adjusting payroll expense levels, the more recent headcount numbers should be used to adjust the level of payroll tax expenses, benefits expenses, and savings plan expenses. 563 As an alternative to its primary line of attack (discussed above), Cities agree with the adjustments recommended by Staff. ETI also agrees, in concept, with the adjustments recommended by Staff, but contends that Ms. Givens made some errors in her calculations. First, according to ETI, Ms. Givens used erroneous headcounts for the end of the Test Year for ETI and ESL According to the Company, 56 ° Cities Ex. 2 (Garrett Direct) at 13-15. 561 Id. at 19. 562 Staff Ex. I (Givens Direct) at 10-12. 563 Id. at 13-15. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE165 PUC DOCKET NO. 39896 ETI's headcount at Test Year-end was 675 and ESI's was 3,054. Ms. Givens wrongly used headcounts of 678 and 3,055, respectively, which caused a double counting of three ETI employees and one ESI employee. 564 Second, Ms. Givens made an error in the calculation of benefits costs associated with the updated ESI headcount. Ms. Givens inadvertently used the ETI percentage in the calculation rather than the ESI percentage shown on her exhibit. 565 Third, Ms. Givens' adjustment for savings plan expense was not necessary and is thus inappropriate. According to ETI witness Considine, savings plan expense is already included in benefits expense levels so it would be double counting to adjust for both benefits expense and savings plan expense. 566 Fourth, Ms. Givens' full-time equivalent calculations need to be corrected. She included an incorrect assumption regarding part time employee salaries. Ms. Givens assumed that a part time employee's average salary is 50 percent of the full time average salary. In his rebuttal testimony, Mr. Considine provided the correct calculation of full time equivalents, thereby making it unnecessary to rely upon an assumed average. 567 According to Mr. Considine, the combined impacts of these errors is that Ms. Givens' ETI headcount adjustment overstated her O&M payroll reduction by $224,217, and her 568 ESI headcount adjustment understated her O&M payroll increase by $37,531. No party challenged these corrected numbers. The Al.J s are unpersuaded by Cities' attempt to exclude the April 2012 pay raises. There can be no real dispute about the fact that the pay raises are known and measurable. Moreover, there is an obvious logical inconsistency in the Cities' position - on the one hand they oppose consideration of certain pay raises because they fall outside the Test Year, and on the other hand they support consideration of headcount reductions even though they also fall well outside the Test Year. The ALls are also persuaded that, conceptually, the adjustments suggested by Staff are reasonable and appropriate. Indeed, all parties agree on this point. Moreover, no party challenged 564 ETI Ex. 46 (Considine Rebuttal) at 32-33. 565 Id. at 33. 566 Id. 567 Id. at 34. 568 Id. at MPC-R-5, and MPC-R-6. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 166 PUC DOCKET NO. 39896 the corrections to Staff's adjustments that were suggested by ETI, and the AU s can find no basis for challenging those corrections. Thus, the AU s recommend that the Commission: ( 1) accept the payroll adjustments proposed in the ETI application~ and (2) accept the further payroll adjustments proposed by Staff, corrected by ETI. 2. Incentive Compensation One of the hotly contested issues concerns the extent to which ETI should be allowed to recover, through its rates, the incentive compensation it pays to its employees. All parties agree that Commission precedent generally identifies two types of incentive compensation, only one of which is recoverable. Specifically, pursuant to Commission precedent, incentive compensation that is tied to operational goals is recoverable, while incentive compensation that is tied to financial goals is not. 569 In its application, however, ETI requests that it be allowed to recover its Test Year costs of all of its incentive compensation costs, regardless of whether those costs are tied to operational goals or to financial goals. (a) Financially Based Incentive Compensation Should Not Be Recoverable ETI acknowledges that costs of incentive compensation tied to financial goals have typically been disallowed by the Commission. However, ETI asks for the Commission to reconsider its precedents on this issue. 570 ETI argues that the Commission precedent is not, and should not be, a hard and fast rule. ETI contends that the reason why cost recovery has been denied for incentive compensation in prior rates cases is that, in those prior cases, there was "a lack of evidence showing sufficient customer benefits."571 ETI asserts that, in this case, it has assembled evidence not previously considered by the Commission that shows the benefits to customers of using financial 569 See, e.g.,TIBC Initial Brief at 51-52; see also AEP Application of AEP Texas Central Company for Authority to Change Rates, See Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007); Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170 (Aug. 15, 2005). 570 Tr. at 1726. 571 ETI Initial Brief at 129. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE 167 PUC DOCKET NO. 39896 measures in incentive compensation programs. For example, ETI argues that incentive compensation that encourages the financial health of a company also benefits customers because: (1) if a company maintains a financially healthy position, it will tend to have a lower cost of capital that will in tum benefit customers through lower rates; (2) a financially healthy company will be more prepared for emergency events such as storms (which is particularly important in the Gulf Coast areas served by ETI, which are subject to experiencing hurricanes); and (3) with financial health, the costs of doing business with suppliers (of both goods and services, including labor) will remain lower because, for example, if a company was not in a financially stable condition, suppliers would tend to demand higher prices or more onerous credit terms, resulting in higher costs that would lead to higher rates than would otherwise occur. ETI witness Kevin Gardner, Vice President of Human Resources for ESI, testified that customers receive benefits from those portions of the incentive compensation plans that are tied to financial goals and measures. He explained that incentive compensation based on financial metrics is a reasonable, necessary, and common component of compensation for companies like ETI. He also opined that such incentives are a market necessity that ETI must include in its compensation package so that it can hire and retain talented employees. He contended that customers benefit from the incentives because they attract and keep qualified people. 572 Mr. Gardner further testified that disallowing financially-based incentives would only encourage utilities to eliminate them, thus weakening the alignment of employees' financial interests with the interest of the ratepayers in having an efficiently run and financially healthy utility. He opined that having only operational incentives could encourage utilities to overspend in some areas resulting in an incomplete, unbalanced incentive program that would be atypical when compared with American industry in general. 573 A second ETI witness, Dr. Jay Hartzell, also testified in favor of the concept of allowing ETI to recover its costs associated with its financially-based incentive compensation. He is a professor of 572 ETI Ex. 36 (Gardner Direct) at 31. 573 Id. at 32. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 168 PUC DOCKET NO. 39896 finance in the business school at the University of Texas at Austin. Dr. Hartzell acknowledged the historical distinction that has been made by the Commission between compensation tied to financial measures and compensation tied to operational measures. However, he argues that this distinction is based upon a "false dichotomy" and that the more appropriate focus should be on whether customers benefit from the incentive in question, regardless of whether it is a financial or operational incentive. 574 Dr. Hartzell summarized his key opinion as follows: In my opm1on, a well-designed compensation plan that includes incentive compensation tied to cost controls, profitability, and stock prices would tend to provide greater benefits to customers than an otherwise similar compensation plan that did not include any such incentive compensation. 575 Dr. Hartzell argues that compensation linked to stock prices (provided it is part of a reasonable, well-designed compensation plan) has four advantages for customers, : • helps ensure that managers will consider the financial health of the company when they make decisions, and it is in customers' interests for the company be fmancially healthy; • provides an incentive for managers and employees to ensure that the company operates efficiently, resulting in lower rates than would otherwise occur; • provides a monitoring mechanism for managerial decision-making and the overall quality of management; and • results in lower customer costs because capital markets will tend to reward efficient long-term investments or capital expenditures. 576 Dr. Hartzell cited a number of studies which support the theory that the benefits of incentive compensation linked to stock price and profitability measures extend to customers of the company, such as by lowering the company's cost of capital, increasing the company's ability to respond to 574 ETI Ex. 15 (Hartzell Direct) at 3-4, 6, and 9-10. 575 Id. at 7. 576 Id. at 13-14. SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE 169 PUC DOCKET NO. 39896 external shocks, improving customer satisfaction, and increasing oversight on managerial decisions. 577 Conversely, Dr. Hartzell opined that if the use of incentive compensation linked to profitability and stock prices is discouraged, via Commission policy disallowing recovery of the costs of such compensation, then utility customers would be adversely affected. For example, if employees did not receive any incentive compensation, salaries would have to be higher to attract and retain the same quality of talent. Dr. Hartzell also testified that a compensation plan solely consisting of salary and incentives based on operational performance could likely lead to "horizon problems," meaning that, absent incentives to focus on the long run health of the company, managers might maximize their immediate compensation at the expense of longer-run benefits that the customer could have enjoyed. 578 All of the other parties oppose ETI' s efforts to recover the costs of its incentive compensation tied to financial goals. The parties uniformly agree that the Commission has a well-established and straightforward policy regarding the recoverability of incentive compensation through rates: incentive compensation that is tied to operational goals is recoverable; incentive compensation tied to financial goals is not. 579 They contend that ETI' s position in this case flies directly in the face of that policy. TIEC points out that ETI has offered no legal authority, such as a statute or rule, which would justify its desire to have the Commission reverse its policy and allow the recovery of incentive compensation tied to financial goals. State Agencies similarly argue that ETI failed to establish a reason why the Commission should deviate from its long-standing policy. The parties also support the reasoning behind the Commission's policy: that financially-based incentives are of more immediate benefit to shareholders, not ratepayers, and therefore are not necessary and reasonable for the provision of service. 577 ETI Ex. 15 (Hartzell Direct) at 15-21. 578 Id. at 22-25. 579 TIEC Reply Brief at 35; State Agencies Initial Brief at 14; OPC Reply Brief at 12; Staff Initial Brief at 56; Cities Initial Brief at 67; see also, Application ofAEP Texas Central Company for Authority to Change Rates, Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007); Application ofAEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170 (Aug. 15, 2005). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 170 PUC DOCKET NO. 39896 State Agencies point out that, in support of his theory that financially-based incentives provide benefits to ratepayers, Dr. Hartzell relied upon studies of utilities in competitive markets. Thus, State Agencies contend, the studies are of little to no benefit in evaluating the effects of financially-based incentives upon ETI customers because ETI is a monopoly that is not subject to competitive pressures. Moreover, State Agencies examine at length the underlying studies relied upon by Dr. Hartzell and assert, essentially, that the studies do not fully support the findings that Dr. Hartzell ascribes to them. Staff refutes ETI's contention that the only reason why cost recovery has historically been denied for financially-based incentive compensation is that there has been a lack of evidence showing customer benefits. For example, Staff points out that, in one of the prior dockets cited by ETI, the Commission disallowed recovery for financially-based incentive costs after stating, "Incentive compensation based on financial measures or goals is of more immediate benefit to shareholders." 580 This suggests that the question is not, as ETI contends, whether the incentives provide any benefit to ratepayers. Rather, the question is whether the incentives are primarily intended to provide benefits to shareholders. Mark Garrett, an attorney and certified public accountant who works as a consultant in the area of public utility regulation, testified on behalf of the Cities in opposition to cost recovery for financially-based incentive compensation. He stated there are a number of reasons why it makes sense to exclude financially based incentive costs from rates: (1) there is no certainty from year to year what the level of incentive payments will be (because incentive payments are conditioned upon future events and triggers that might not occur), thereby making it difficult to set rates and recover a level of expense; (2) many of the types of factors that increase earnings per share-such as an unusually hot summer or customer growth-are outside the control of employees and have no value to customers; and (3) earnings-based incentives can discourage energy conservation. 581 Mr. Garrett 580 Staff Reply Brief at 44, quoting Application of Oncor Electric Delivery Company for Authority to Change Rates, Docket No. 35717, Order on Rehearing at FoF 92 (Nov. 30, 2009). 581 Cities Ex. 2 (Garrett Direct) at 29-30 SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE171 PUC DOCKET NO. 39896 also discussed the results of a survey of 24 other states, which revealed that 17 states closely follow Texas' approach, and none allow full recovery of incentive compensation. 582 Mr. Garrett testified that ETI will not be placed at a competitive disadvantage in its ability to obtain and retain qualified employees if its financially-based incentives are disallowed. He stated that the Company's total payroll costs for 2011 were 10 percent above the market price, and that most of the above-market payroll costs derived from the incentive program. 583 The AI.Js conclude that ETI should not be entitled to recover its financially based incentive compensation costs. Based upon prior Commission precedents, the AI.Js conclude that the issue is not, as ETI contends, whether such incentives might provide any benefits to customers. The proper question to be asked is whether they provide benefits most immediately or predominantly to shareholders. Without a doubt, the primary purpose of financially based incentives, such as incentives tied to earnings per share or stock price, is to benefit shareholders, not ratepayers. Even construing Dr. Harzell's testimony in the most generous light, any benefits that might accrue to ratepayers would be merely tangential to that primary purpose. Moreover, even if the AI.Js were to completely accept as true the opinions offered by Dr. Hartzell, it would be of limited benefit to ETI because his opinions were almost completely theoretical. The premise of his testimony was that "a well-designed compensation plan" that includes incentive compensation tied to financial goals would "tend to provide greater benefits to customers" than a plan that did not include such compensation. 584 He stressed that the customer benefits of incentive compensation tied to financial goals can only exist if such compensation is part of a larger, reasonable, and well-designed overall compensation plan. 585 However, he did not meaningfully apply this abstract theory to ETI's compensation plan. For example, Dr. Harzell did not offer an evaluation of ETI' s compensation plan and conclude that it is "well designed," nor did 582 Id. at 32-38. 583 Id. at 45-46. 584 ETI Ex. 15 (Hartzell Direct) at 7 (emphasis added). 585 See, e.g., ETI Ex. 15 (Hartzell Direct) at 13. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE172 PUC DOCKET NO. 39896 he testify that ETI' s incentives tied to financial goals actually provide benefits to its customers. He admitted that he did not study the details of ETI' s incentive plans, nor did he do any type of analysis to see if the costs of ETI's incentive programs outweighed their benefits. 586 He did not know the amounts of incentive compensation that was paid by ETI. 587 One of his major premises was that financially-based incentives can benefit customers by lowering their costs, but he did not know how ETI customer's costs compared with customer costs in the other Entergy operating companies. 588 Another of his major premises was that financially-based incentives can benefit customers by ensuring the financial health of the Company, but he made no attempt to determine whether ETI was, in fact, a financially healthy company. 589 By confining his testimony to the abstract, it is impossible to know whether Dr. Hartzell believes that ETI's incentive compensation tied to financial goals achieves the customer benefits that he believes such compensation can theoretically achieve. It is true that Mr. Gardner described some of the specifics of ETI' s incentive plans. However, because Dr. Hartzell did not explain the metrics of what he would consider "a well-designed compensation plan," it is impossible to know if ETI's plan meets those metrics. Simply put, the ALls conclude that ETI has failed to establish a sufficient justification for overturning the well-established Commission policy that financially based incentive compensation is not recoverable. (b) The Adjustment for Financially-Based Incentive Compensation Costs Having concluded that ETI is not entitled to recover the costs of its financially based incentive programs, it is necessary to determine the amount of those costs so that they may be removed from consideration in this rate case. The parties disagree on the correct amount. Staff 586 Tr. at 484. 587 Tr. at 478. 588 Tr. at 480. 589 Tr. at481-82. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 173 PUC DOCKET NO. 39896 590 argues that $5 .3 million of ETI' s incentive compensation is financially based. TIEC contends the 591 592 correct number is $6.2 million. Cities contend it is $8.4 million. Broadly speaking, ETI has two categories of incentive compensation programs - annual programs and long-term programs. ETI witness Gardner testified that 100 percent of ETI' s long-term programs are financially based, whereas an average, representing a far lower percentage, of the Company's annual programs are financially based. 593 Staff witness Givens applied those percentages to determine her estimate of the amount spent by ETI in the Test Year on financially based incentives. As to the Company's long-term programs, she recommended removing the entire costs of those programs (i.e. 100 percent) from the cost of service. As to the Company's annual programs, she recommended removing average percentage of the costs of those programs. Ms. Givens then applied the FICA tax rate to the total amount she identified as financially based costs to account for direct taxes that ETI would have paid as a result of those costs. By her estimate, the FICA taxes associated with ETI's financially based incentives paid in the Test Year totaled $429,096. In total, Ms. Givens recommended removing $5,609,093 (representing ETI' s financially based incen,tives paid in the Test Year, plus FICA taxes associated with those payments) fromETI's requested O&M expenses. However, based upon subsequent additional information supplied by ETI594 relative to the actual payroll taxes paid by the Company for its financially based incentive compensation, Staff has agreed to lower its estimate of FICA taxes from $429,096 to $143,801. Thus, Staff now recommends removing $5,323,798 (representing ETI's financially based incentives paid in the Test Year, plus FICA taxes associated with those payments) from ETI' s requested O&M expenses. 595 590 Staff Initial Briefat 56. (As discussed more below, Staff's original estimate was roughly $5.6 million. The estimate was reduced, however, in response to supplemental payroll tax information supplied to Staff by ETI.) 591 TIEC Initial Brief at 53-54. 592 Cities Initial Brief at 70. 593 ETI Ex. 36 (Gardner Direct) at 30. 594 ETI Ex. 46 (Considine Rebuttal). 595 Staff Ex. I (Givens Direct) at 15-22; Staff Initial Brief at 56-63. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE174 PUC DOCKET NO. 39896 Like Ms. Givens for Staff, TIEC witness Pollock relied on the numbers and percentages concerning ETI's incentive programs that were provided by Mr. Gardner. However, Mr. Pollock calculated those numbers and percentages in a slightly different manner, leading to a different recommended reduction amount. Just as Ms. Givens did, as to the Company's long-term programs, he recommended removing the entire costs of those programs from the cost of service. ETI witness Gardner testified that actual percentages of each annual program were quite different than the average percentages for all programs used by Ms. Givens. 596 Thus, as to the Company's annual programs, while Ms. Givens applied the average percentage reduction to all of the annual programs, Mr. Pollock applied the actual percentage reductions applicable to each of the annual programs. Based on Mr. Pollock's calculations, TIEC recommends removing $6,196,037 (representing ETI's financially based incentives paid in the Test Year) fromETI's requested O&M expenses. 597 TIEC appears not to have taken into account any payroll taxes associated with ETI' s financially based incentives. Cities witness Garrett took a substantially different approach when he calculated his estimate of ETI's financially based incentive costs. He agreed with Ms. Givens and Mr. Pollock that 100 percent of the Company's long-term program costs should be removed from the cost of service. As to the annual programs, however, Mr. Garrett defined what qualifies as "financially based" much more broadly than ETI, Staff, and TIEC. ETI witness Gardner testified that, when the Company's five annual programs were averaged together, specific percentages of those programs were financially based, aimed at "cost control," and aimed at "cost control, operational, safety."598 Mr. Garrett added together the percentages representing the financially-based costs, the cost-control costs, and roughly one-third of the cost-control, operational safety costs to arrive at the figure he identified as the amount of ETI' s costs for its annual programs that is "related to financial performance measures." 599 Cities contend this approach is supported by the decision in a prior 596 ETI Ex. 36 (Gardner Direct) at 30 and KGG-4. 597 TIEC Ex. l (Pollock Direct) at 41-45 and JP-7; TIEC Initial Brief at 51-54. 598 ETI Ex. 36 (Gardner Direct) at 30 and KGG-4. 599 Cities Ex. 2 (Garrett Direct) at 39-40, 46-50, MG2.10. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE175 PUC DOCKET NO. 39896 docket. 600 Based on Mr. Garrett's calculations, Cities recommend removing $8,397,232 (representing ETI's incentives "related to financial performance measures" paid in the Test Year) from ETI' s requested O&M expenses.601 Mr. Garrett also agreed with Ms. Givens that an additional reduction should be made to account for the FICA taxes that ETI would have paid as a result of those costs. 602 The Al.Js reject Cities' attempt to broadly expand the definition of what qualifies as a financially based incentive to include items such as cost control measures. Cities' primary justification for doing so is that the Commission has done so previously in the AEP Texas case. As pointed out by ETI, however, the Commission did so in that case merely because AEP Texas lumped its cost control measures in with its financially based incentive costs. The evidence in this case demonstrates that ratepayers benefit when a utility incentivizes its employee to control costs. Even TIEC witness Pollock testified that "incentives that encourage employees to minimize costs are probably more or less in the best interest of ratepayers."603 ETI further provided evidence establishing that cost control incentives that result in lower costs for the Company likewise result in lower rates for customers. 604 As to the approaches advocated by TIEC and Staff, the AU s conclude that TIEC' s approach more accurately captures the true cost of ETI' s financially based incentive programs. Rather than averaging across all of ETI's annual programs (as was done by Staff), TIEC used the percentage applicable to the single annual program that included a component of financially based costs. Thus, theALls recommend removing $6,196,037 (representing ETI's financially based incentives paid in the Test Year) from ETI's requested O&M expenses. Additionally, the Al.Js agree with Staff and 600 Cities Initial Brief at 68, Application of AEP Texas Central Company for Authority to Change Rages, Docket No. 28840, Final Order (August 15, 2005). 601 Cities Ex. 1 (Garrett Direct) at 51-52 and MG2. l O; Cities Initial Brief at 70. 602 Cities Ex. 1 (Garrett Direct) at 53. 603 Tr. at 1528. 604 ETI Ex. 50 (Gardner Rebuttal) at 6-7, ETI Initial Brief at 137-38. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE176 PUC DOCKET NO. 39896 Cities that an additional reduction should be made to account for the FICA taxes that ETI would have paid as a result of those costs. That amount is not specifically known at this time. 3. Compensation and Benefits Levels In the application, ETI included, as part of its labor costs, $54,965,005 in base payroll paid by ETI and ESI in the Test Year. It also included $20,428,817 in costs associated with various benefits (such as medical/dental, and life insurance) that ETI and ESI provided to their employees. 605 Cities contend that the amounts for base pay and the benefits package should be reduced by $989,370 and $2,860,034, respectively, because the amounts paid were above the market price.606 No other party challenges the reasonableness of the base payroll and benefits package. As to base payroll, Cities contends that the amount paid by ETI and ESI was 1.8 percent above the prevailing market price (above market). 607 Cities witness Garrett acknowledges that ETI and ESI are free to pay their employees at above market wages, but he contends that ratepayers should only be asked to pay the market rate for wages, which he contends constitute the only "necessary'' costs of providing utility service. Thus, Mr. Garrett and Cities recommend a 1.8 percent downward adjustment to base payroll expense (or $989,370) "to bring the company's base payroll down to a market-based level."608 As to the Company's benefits package, Cities points out that the amount paid by ETI and ESI was 14 percent above market when compared to a peer group of Fortune 500 companies. 609 Cities witness Garrett again contends that ratepayers should only be asked to pay the market rate for benefits, which he contends constitute the only "necessary" costs of providing utility service. Thus, 605 Cities Ex. 2 (Garrett Direct) at 25, MG2.8, and MG2.9. 606 Id. 607 Id. at 25 and MG2.8. 608 Id. at 26-27 and MG2.8. 609 Id. at 58 and MG2.9; ETI Ex. 36 (Gardner Direct) at 41-42. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 177 PUC DOCKET NO. 39896 Mr. Garrett and Cities recommend a 14 percent downward adjustment to benefits expenses (or $2,860,034).610 ETI concedes that its Test Year base pay was 1.8 percent "above the market median," but argues that this is not the same thing as being "above market." As ETI witness Gardner explained, "being 'at market' means being within a reasonable range, such as +/-10 percent, of the market median; therefore, the Company's base pay levels are at market."611 According to Mr. Gardner, some compensation consultants use an even broader range, such as a+/- 15 percent range, for determining whether compensation levels are at market. 612 Mr. Gardner testified that, because no two jobs are likely to be identical, attempting to benchmark jobs to a "market price" is an inexact science, involving inherent imprecision. Thus, Mr. Gardner testified that, when using a benchmark analysis to compare companies' levels of compensation, it is advisable to view the market level of compensation as a range (e.g.,+/- 10 percent of a mid-point) rather than a precise, single point. 613 ETI also disputes Cities' contention that the Test Year costs of the Company's benefits package were 14 percent "above market." Mr. Gardner acknowledged that the costs were 14 percent higher than those of Fortune 500 companies, but he pointed out the costs were only 1 percent above the market median of a peer group of utility companies. 614 ETI contends that the comparison against the peer group of utility companies provides a more appropriate comparison for ETI than Fortune 500 companies. ETI also points out that, even if equal weight were given to the comparisons against the Fortune 500 companies and the peer utilities group, the value of the Company's benefit plans would average within a +/- 10 percent range and, therefore, be at market. Thus, ETI argues that its benefit plan levels are within a reasonable range, and no disallowance should be required. 615 610 Cities Ex. 2 (Garrett Direct) at 58-59 and MG2.9. 611 ETI Ex. 50 (Gardner Rebuttal) at 11. 612 ETI Ex. 36 (Gardner Direct) at 23, and ETI Ex. 50 (Gardner Rebuttal) at 11 n. l. 613 ETI Ex. 50 (Gardner Rebuttal) at 11-12. 614 ETI Ex. 36 (Gardner Direct) at 42. 615 ETI Ex. 50 (Gardner Rebuttal) at 13-14; ETI Initial Brief at 139-142. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 178 PUC DOCKET NO. 39896 The ALls conclude that ETI has met its burden to prove the reasonableness of its base pay and incentive package costs. The ALls agree that it is reasonable to view market price for these categories of costs as lying within a range of +/- 10 percent of median, rather than being a single point along a spectrum. As to both base pay and the incentive package, ETI has proven that its costs fall within such an acceptable range. Accordingly, the ALls recommend rejecting the adjustments sought by Cities. 4. Non-Qualified Executive Retirement Benefits ETI provides three types of supplemental executive retirement plans: the Pension Equalization Plan, the Supplemental Retirement Plan, and the System Executive Retirement Plan. 616 In the application, ETI included, as part of its labor costs, $2, 114,931 in costs associated with its executive retirement plans. The expenses represent non-qualifying retirement plan expenses designed to provide retirement benefits to key managerial employees and executives who are invited to participate in the plans. They are generally available only to employees and executives earning more than $245,000 per year. 617 On behalf of the Staff, Ms. Givens recommended a complete disallowance of the costs for these programs, on the grounds that they are offered to only select, highly compensated employees and are excessive. Ms. Givens offered the opinion that the expenses were not reasonable and necessary forthe provision of electric utility service and were not in the public interest.618 On behalf of Cities, Mr. Garrett agreed with Ms. Givens' recommendation, arguing that it is fair to have ratepayers pay for benefits included in regular pension plans, but that shareholders ought to pay for any additional benefits included in supplemental plans, "since these costs are not necessary for the provision of utility service, but are instead discretionary costs of the shareholders."619 Mr. Garrett also testified that costs associated with supplemental executive retirement plans are typically 616 ETI Ex. 50 (Gardner Rebuttal) at 14. 617 Staff Ex. l (Givens Direct) at 22-23; Cities Ex. 2 (Garrett Direct) at 54. 618 Staff Ex. l (Givens Direct) at 23; Staff Initial Brief at 64. 619 Cities Ex. 2 (Garrett Direct) at 55; Cities Initial Brief at 71-72. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 179 PUC DOCKET NO. 39896 excluded by utility commissions in Oklahoma, Oregon, Idaho, Arizona, and Nevada.620 On behalf of OPC, Dr. Szerszen also recommended a complete disallowance of the portion of these costs allocated from ESI to ETI.621 She stated that ETI has not shown that ratepayers benefit from the expenses, the costs are not necessary to provide utility service, and that the ESI allocation method is 622 unjustified. ETI disagrees with all of these criticisms and maintains that the costs of the plans should be recoverable. ETI witness Gardner testified that the supplemental executive retirement plans are needed for attracting, retaining, and motivating highly competent and qualified leaders. He explained that the Pension Equalization Plan provides supplemental retirement benefits to account for the fact that Internal Revenue Code regulations limit the level of retirement benefits that qualify for tax treatment favorable to ETI and Entergy. The existence of this supplemental benefit program allows the Company to pay retirement benefits to highly-compensated employees that are proportionate to the compensation they receive while active in their employment. The Supplemental Retirement Plan and the System Executive Retirement Plan provide supplemental benefits beyond the amounts restricted in the qualified plan to some participants to attract, retain, and motivate employees.623 According to Mr. Gardner, these types of retirement benefits are widely provided by companies within the utility business sector. 624 Accordingly, ETI argues that it needs to offer them in order to be competitive in the employment market with peer companies, and thereby to retain and adequately compensate these employees in terms of future retirement benefits. The ALl s conclude that the supplemental executive retirement plans are not reasonable and necessary for the provision of electric utility service and are not in the public interest. They are non-qualifying retirement plan available only to employees and executives earning more than 62 ° Cities Ex. 2 (Garrett Direct) at 56-57. 621 OPC Ex. 1 (Szerzen Direct) at 68. Dr. Szerzen quantifies the costs of the plans as $1,391,861 (a much lower estimate than those of Ms. Givens and Mr. Garrett). 622 Id. at 68-69. 623 ETI Ex. 50 (Gardner Rebuttal) at 15-16. 624 Id. at 16. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 180 PUC DOCKET NO. 39896 $245,000 per year, and they constitute benefits over and above the Company's standard retirement benefits package. Because these costs are not necessary for the provision of utility service, but are instead discretionary costs, they should be paid by the shareholders. Accordingly, the AUs recommend an adjustment to remove $2, 114,931, representing the full costs associated with ETI' s non-qualified executive retirement benefits. 5. Employee Relocation Costs In the application, ETI included, as part of its labor costs, $436,723 in employee relocation 625 costs. ETI contends that, in order to be competitive in the employment market, it must provide relocation assistance to certain of its employees. ETI witness Gardner testified that ETI' s relocation policies and costs are reasonable and consistent with general industry practice. He also testified that the Company's average relocation costs are in line with the relocation costs for the companies surveyed by the Employee Relocation Council. 626 Staff recommends an adjustment to remove the entire $436,723 of ETI's relocation expenses. 627 No other party challenged the legitimacy of relocation expenses. Staff points out that ETI pays 110 percent of the market median for total annual compensation. 628 Staff contends that the fact that ETI pays more than the average market wage demonstrates that employees should be sufficiently enticed to join and move around within its organization without the need for ETI to pay relocation expenses to attract employees. Therefore, Staff argues that the relocation expenses do not meet the reasonable and necessary standard required for inclusion in cost of service, nor are the expenses in the public interest. 629 Staff also points out that similar types of payments were removed 625 Staff Ex. 1 (Givens Direct) at 25. 626 ETI Ex. 36 (Gardner Direct) at 45-46. 627 Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24. 628 Staff Ex. 1 (Givens Direct) at 24 (citing ETI Ex. 36 (Gardner Direct) at 26). 629 Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 181 PUC DOCKET NO. 39896 from cost of service in recent proceedings, such as in Docket No. 28906, where payments for moving expenses or signing bonuses were removed from cost of service. 630 ETI responds by pointing out that Staff does not challenge the reasonableness of the amount spent on relocations by ETI. It also contends that most of its peers offer moving assistance. Thus, it would be competitively disadvantaged if it did not offer it as well. ETI reiterates that its relocation costs are reasonable and necessary and should be authorized. 631 The AU s conclude that ETI has the better argument. There is no allegation that ETI was too lavish in its relocation expenditures. The only complaint offered by Staff is that ETI' s overall compensation costs are 110 percent of the market median. It does not necessarily follow that the relocation program is unnecessary. ETI provided substantial evidence that, without a relocation program, it would be at a competitive disadvantage with its peers. Accordingly, the AI.Js reject Staffs request to disallow the Company's relocation expenses. 6. Executive Perquisites In the application, ETI included, as part of its labor costs, $40,620 in costs associated with its executive perquisites. Those perquisites consist of financial counseling and tax gross-ups for system officers and executives. Specifically, the financial counseling program promotes maximizing investment growth opportunities for eligible officers and executives, and allows reimbursement for certain expenses incurred for personal financial counseling services. 632 Staff recommends an adjustment to remove the full cost of the executive perquisites ($40,620), reasoning that the costs are not reasonable and necessary for the provision of electric utility service. 633 ETI does not oppose that 630 Stafflnitial Brief at 64; Staff Ex. 1 (Givens Direct) at 24, citing Application ofLCRA Transmission Services Corporation to Change Rates, Docket No. 28906, Final Order (Apr. 5, 2005). 631 ETI Initial Brief at 143. 632 Staff Ex. 1 (Givens Direct) at 23. 633 Staff Initial Brief at 65; Staff Ex. 1 (Givens Direct) at 23. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 182 PUC DOCKET NO. 39896 adjustment.634 The AU s agree that the adjustment is warranted. Therefore, the AUs recommend an adjustment to remove $40,620, representing the full cost of ETI' s executive perquisite costs. E. Interest on Customer Deposits Staff witness Givens adjusted ETI's requested interest expense of $68,985 by removing $(25,938) from FERC account 431. 635 This decrease is a result of applying the interest rate of 636 0.12 percent for calendar year 2012 on deposits held by utilities. Using the active customer deposits amount of $35,872,476 and the 2012 interest rate, Ms. Givens calculated a recommended interest expense of $43,047 ($35,872,476 multiplied by .12 percent).637 This change, which reflects Commission-approved interest rates for 2012 as set in December 2011, complies with Project No. 39008 and ETI agreed with this amount. Accordingly, the ALls recommend that the Commission approve this amount. F. Property (Ad Valorem) Tax Expense During the Test Year, ETI's property tax expense equaled $23,708,829.638 Patricia Galbraith, ETI' s Tax Officer, testified that a proforma adjustment should be made to this level of expense for a known and measurable change that reflects the level of property tax expense ETI will experience in the Rate Year. Specifically, her proposed adjustment would increase the Test Year level of expense by $2,592,420 to $26,301,249. 639 As Ms. Galbraith testified, ETI's property tax expense for the calendar year 2012 will be paid in January of 2013 and be based on 2011 calendar year-end values for both net operating income and net plant amounts. 640 Her proposed adjustment is based on an 634 ETI Initial Brief at 144. 635 Staff Ex. l (Givens Direct) at 24. 636 Setting Interest Rates for Calendar Year 2012, Project No. 39008, Order (Dec. 8, 2011). 637 Staff Ex. l (Givens Direct) at 24-25. 638 ETI Ex. 26 (Galbraith Direct) at 5; ETI Ex. 3 at Sched. G-9. 639 ETI Ex. 26 (Galbraith Direct) at 5 and PAG-1; ETI Ex. 3 at Sched. G-9. 640 Tr. at 1235. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 183 PUC DOCKET NO. 39896 expected ad valorem rate increase of 1 percent and expected increases in both net plant values and 641 ETI net operating income that will equal 9.81 percent. TIEC, Cities, and Staff oppose the property tax adjustment proposed by ETI. TIEC argues that ETI' s proposed adjustment should be rejected entirely, on the grounds that it is not a known and measurable change from ETI' s Test Year property tax costs. Ms. Galbraith admitted that she does not know, with certainty, what the relevant property tax rate will be in 2012, nor has ETI received any tax bills advising that tax rates will rise. 642 Thus, TIEC witness Pollock testified that ETI' s proposed adjustment is not known and measurable and recommended that the Commission reject the adjustment and include only the Test Year level of expense in cost of service.643 TIEC further points out that the Commission has twice rejected requests to include projected property tax expense in rates. 644 For example, in Docket No. 28813, Cap Rock prepared an independent analysis indicating that property taxes were expected to increase to $2,700,000 per year from its test year tax level of approximately $900,000 per year. The analysis used an estimated tax assessment of $110,000 with an estimated tax rate of $2.47 per $100 of value. The ALls in that case concluded that the property tax increases were estimates at the time of the hearing, and thus they were not known and measurable and should not be allowed. 645 Subsequently, the Commission adopted the ALls' finding. 646 The Commission rejected a similar request from ETI's predecessor Gulf States Utilities (GSU). 647 In consolidated Docket No. 8702, the Commission rejected GSU's request for projected 1989 property 641 ETI Ex. 26 (Galbraith Direct) at PAG-1. 642 Tr. at 1221, 1238. 643 TIEC Ex. 1 (Pollock Direct) at 40-41. 644 In re Cap Rock Corp., Petition ofPUC (Staff) to Inquire into the Reasonableness ofthe Rates and Services of Cap Rock Energy Corporation, Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005) ("Cap Rock failed to prove any increase in property taxes above those in the test year-$899,597-was known and measurable."); Application of Gulf States Utilities Company for Authority to Change Rates, Application of Sam Rayburn G&T Electric Coop., Inc. for Sale Transfer or Merger, Appeal of GulfStates Utilities Company from Rate Proceedings of Various Municipalities, Docket Nos. 8702, 8922, 8939, 8940, 8946, 8233, 8944, 8945, 8947, 8948 and 8949, Order at FoF 111(May2, 1991) ("The 1988 calendar year level of actual property taxes paid should be used in determining rate year taxes because it is a known and measurable change."). 645 Docket No. 28813, PFD at 99 (Mar. 17, 2005). 646 Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005). 647 Docket No. 8702, Order at FoF 111 (May 2, 1991). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 184 PUC DOCKET NO. 39896 taxes and instead only allowed the actual calendar year property tax expenses. 648 In both cases the Commission found that projected tax expense is not a known and measurable change. 649 Accordingly, TIEC contends that ETI' s request for a forecasted tax expense increase should be rejected. 650 Staff concedes that some level of increase is warranted but argues that the increase should be smaller than ETI is asking for. Rather than an increase of $2,592,420, Staff contends that ETI' s Test Year property tax expenses should be adjusted upward by only $1,214,688. 651 Staff witness Givens arrived at this increase by applying the effective tax rate forthe calendar year2011 to the Staffs Test Year end plant in service recommendation. She testified that both of these inputs to her calculation are known and measurable and thus may be used to determine the increase. 652 Cities also concede that some level of increase is warranted, but argue that the increase should be smaller than ETI is asking for, and smaller than Staff proposes. Cities contend that ETI' s Test Year property tax expenses should be adjusted upward by only 1,134,442. 653 Cities witness Garrett offered the opinion that ETI' s proposed adjustment was based on estimates that were unreasonably high when compared to the actual tax valuation increases experienced since 2008. Mr. Garrett arrived at his projected increase in tax expense by applying the average annual valuation increase experienced over the period of 2009-11 to net plant value for 2011. Cities argue that both of these inputs to the calculation are known and measurable and thus may be used to determine the increase. 654 648 Docket No. 8702, Order at 52. 649 Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005); Docket No. 8702, Order at 52, FoF 111 (May 2, 1991). 650 TIEC Initial Brief at 54-56. 651 Staff Ex. 1 (Givens Direct) at 25. 652 Id. at 25-26. 653 Cities Ex. 2 (Garrett Direct) at 61. 654 Id. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 185 PUC DOCKET NO. 39896 ETI responds to its opponents by pointing out that the Commission has, in the past, recognized that the adjustment proposed by Staff, which was obtained by applying a historical effective tax rate to the level of test year end plant in service, is known, measurable, and appropriate. 655 ETI also notes that, although it had not done so at the time Ms. Galbraith filed her testimony, ETI has since filed its 2011 year end FERC Form 1 data and now knows both the final net income amounts and net plant values for year end 2011 that will be used to determine the Company's 2012 tax expense (that will be paid in January of 2013 ). 656 ETI contends that those known values are substantially larger than the estimates used by Ms. Galbraith when she calculated the proposed adjustment, such that the known increases in 2011 net operating income and net plant amounts over 2010 are so large that, even without the 1 percent increase in tax rate assumed in the property tax adjustment, Rate Year property tax expenses will be larger than the $26,301,249 amount requested by the Company. 657 The issue with regard to property taxes is whether a level of increase is known and measurable. The ALls conclude that the approach taken by Staff does the best job of generating a known and measurable value for ETI' s property tax burden in the Rate Year. As explained above, Staffs approach is supported by prior Commission precedent. Moreover, unlike the approaches advocated by ETI and Cities, Staffs approach requires no guesswork about future tax rates. Accordingly, the AUs recommend that ETI's property tax burden should be adjusted upward by applying the effective tax rate for the calendar year 2011 to the final, adopted Test Year-end plant in service value for ETI. 655 ETI Initial Brief at 145; see also, Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Final Order at FOF 189-191 (Aug. 15, 2005); Petition of General Counsel to Inquire Into the Reasonableness of the Rates and Services of Central Telephone Company of Texas, Docket No. 9981, 19 Tex. P.U.C. Bull. 936, 1080-82, 1217 (Sept. 8, 1993);Application of Central Power and Light Company for Rate Changes and Inquiry Into the Company's Prudence with Respect to South Texas Project Unit 2, Docket No. 9561, 17 Tex. P.U.C. BULL. 157, 231-232 (Dec. 19, 1990). 656 Tr. at 1236-37. 657 ETI Initial Brief at 146-47. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE186 PUC DOCKET NO. 39896 G. Advertising, Dues, and Contributions In the application, ETI included, as part of its operating expenses, $2,046,214 in costs associated with advertising, dues, and contributions.658 Staff recommended an adjustment to remove $12,800, representing contributions to organizations primarily focused on influencing legislative activities. Staff reasons that these costs are not reasonable and necessary for the provision of electric utility service. 659 ETI makes no response to the suggested adjustment. 660 The ALls agree that the adjustment is warranted. Therefore, the ALls recommend an adjustment to remove $12,800 from ETI' s costs of advertising, dues and contributions. H. Other Revenue-Related Adjustments Several items within the Company's revenue requirement are interrelated. This means that changes to one area or item will impact one or more additional items, such as the Texas state gross receipts tax, the PUC Assessment tax, and Uncollectible Expenses. 661 From the discussions in briefs, it does not appear that there are any substantive differences among the parties regarding these amounts, which will ultimately be determined during number running. I. Federal Income Tax As explained by ETI witness Rory Roberts, the Company calculated its income tax expense in the cost of service by taking into account only the revenues and expenses included in the cost of 662 service. To the extent the Commission makes changes to the revenues and expenses that are ultimately included in the cost of service, the income tax expense amount included in the cost of 658 ETI Ex. 3, Sched. G-4. 659 Staff Initial Brief at 66; Staff Ex. 1 (Givens Direct) at 26. 660 ETI Initial Brief at 147. 661 Staff Ex. 1 (Givens Direct) at 28-29. 662 ETI Ex. 21 (Roberts Direct) at IO; Ex. 3 Sched. G-7. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 187 PUC DOCKET NO. 39896 service will change accordingly. This represents a proper matching of income tax effects to the expenses and revenues that produced those tax effects.663 Mr. Roberts contended that the Commission's past practice of reducing tax expense for a consolidated tax adjustment based on some measure of the tax "savings" the utility realized by joining in a consolidated group federal income tax return was inappropriate. He testified that it is improper to reduce tax expense for deductions or losses that are not also included in the cost of service. In the case of the Commission's consolidated tax adjustment, tax expense is reduced to the extent that utility income is used to offset non-utility affiliate losses, even though those losses are not 664 included in cost of service or borne in any manner by the utility's customers. Despite his disagreement with the approach, Mr. Roberts performed a calculation of the adjustment using the interest credit methodology adopted by the Commission. He concluded that, instead of positive taxable income, ETI had net tax losses over the 15-year calculation period and thus provided no taxable income that could be used to offset affiliate losses. 665 In fact, over the 15-year period, ETI's tax losses were offset by taxable income produced by other affiliates. Thus, ETI contends that, were the Commission to be consistent in applying its interest credit methodology, it should increase ETI tax expense included in cost of service due to the fact that its affiliates' taxable income had to be used to offset ETI's tax losses. Nevertheless, in its application, ETI rejected the interest credit methodology and has not requested that ETI' s tax expense be increased as a result of the consolidated tax adjustment calculation. No other party to the proceeding challenged the Company's position on federal income tax expense in testimony or at the hearing. The ALls find no reason to do so either. 663 ETI Ex. 21 (Roberts Direct) at 10. 664 Id. at 10-1 L 665 Id. at 10, and RLR-5. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE 188 PUC DOCKET NO. 39896 J. River Bend Decommissioning Expense ETI has an ownership interest in River Bend. In the application, ETI requested that $2,019 ,000 be included in its cost of service to account for the Company's annual decommissioning expenses associated with River Bend. 666 This is the same amount that was requested and approved on December 13, 2010, in Docket No. 37744. 667 The amount of $2,019,000 was derived from an ETI decommissioning study that was completed in 2009. In this case, ETI chose not to propose any change to its 2009 estimate. ETicontends that this decision is supported by an August 9, 2011, letter from the Nuclear Regulatory Commission. 668 Cities argue that the decommissioning expense should be reduced to $1,126,000. 669 Cities point out that the larger amount sought by ETI was merely the amount agreed to by the parties, as opposed to being substantively considered and approved by the Commission in Docket No. 37744.670 In the current case, ETI was asked through discovery to provide an updated estimate of the annual decommissioning expense responsibility for Texas retail customers calculated using the most current Texas jurisdictional decommissioning fund balance. ETI responded that the current annual decommissioning revenue requirement is $1,126,000. 671 Under P.U.C. SUBST. R. 25.231(b)(l)(F)(i), the annual cost of decommissioning for ratemaking purposes must "be determined in each rate case based on . . . the most current information reasonably available regarding the cost of decommissioning, the balance of funds in the decommissioning trust, anticipated escalation rates, the anticipated return on the funds in the decommissioning trust, and other relevant factors." The cost determined must then be expressly included in the cost of service established by the Commission's order. 666 ETI Ex. 3 Scheds. M-1 and M-2; ETI Ex. 8 (Considine Direct) at 57-58. 667 ETI Ex. 8 (Considine Direct) at 58. 668 Id. at 58 and MPC-2. 669 Cities Ex. 2 (Garrett Direct) at 64-65. 670 Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Final Order at FoF 32 (Dec. 13, 2010); Cities Initial Brief at 73. 671 Tr. at 348-49. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE189 PUC DOCKET NO. 39896 The parties agree that $1,126,000 is the best estimate of the current annual revenue requirement to meet ETI' s estimated decommissioning cost. However, ETI relies on P.U.C. SUBST. R. 25.23l(b)(l)(F)(iv) and Staff witness Cutter's testimony to contend that it need not adjust the current amount being charged.672 Pursuant to subpart (iv), ETI is required to periodically study its decommissioning costs, and such a study must be done "at least every five years." Because its last study was done in 2009, ETI contends that it need not do a new study now, but may simply rely of the outcome of its last study, which showed that its annual revenue requirement is $2,019,000. 673 Cities agree that ETI is not required to conduct a new decommissioning study at this time. However, the most current information reasonably available clearly shows that the annual amount required to meet the total cost determined in the Company's last decommissioning study has decreased. Cities argue that to ignore the most current information available disposal would unreasonably shift future costs to current customers and would be a violation of P.U.C. SUBST. R. 25 .231 (b)( 1)(F)(i). The AUs agree. ETI' s annual decommissioning revenue requirement should reflect the most current calculation of $1, 126,000. Therefore, an adjustment of $893,000 to the pro form.a cost of service is needed to reflect the difference between the requested level for decommissioning costs of $2,019,000 and recommended level of $1,126,000. K. Self-Insurance Storm Reserve Expense [Germane to Preliminary Order Issue No. 5] In prior dockets, the Commission authorized ETI to recover $3,650,000 annually for storm damage expenses and to maintain a reasonable and necessary storm damage reserve account of $15,572,000. 674 ETI requests to increase the authorized storm damage reserve account to $17,595,000 (an increase of $2,023,000) and to increase the annual accrual to $8,760,000 (an increase of $5,110,000). ETI's proposed annual accrual is composed of two elements: (1) an annual accrual of $4,890,000 to provide for average annual expected losses from all storms that do not 672 ETI Ex. 46 (Considine Rebuttal) at 38-39. 673 Id. 674 Staff Ex. 4 (Roelse Direct) at 8. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE190 PUC DOCKET NO. 39896 exceed $100 million; and (2) a 20-year annual accrual of $3,870,000 to bring the reserve up from its current deficit of $59,799,744 to ETI's target reserve of $17,595,000. No party disputes that ETI's proposal to self-insure for catastrophic property loss is appropriate under PURA§ 36.064 and P.U.C. SUBST. R. 25.23l(b)(l)(G). However, Cities, OPC, and Staff oppose the amount of ETI' s proposed annual accrual, and Cities and OPC also oppose ETI' s proposed target reserve. The parties' recommendations are: Annual Accrual Target Reserve Current $3,650,000 $15,572,000 ETI $8,760,000 $17,595,000 Cities $6,150,339 $15,572,000 OPC-1 $2,335,047 $15,572,000 OPC-2 $3,650,000 $15,572,000 Staff $8,270,000 $17,595,000 The first component of ETI' s requested annual accrual is $4,890,000 for expected annual losses. ETI explains that this is the amount of annual losses projected to be incurred by ETI from all storm damage, except those over $100 million (the minimum amount likely to be securitized),675 adjusted to reflect current conditions and current cost levels. 676 This recommended accrual was calculated by ETI witness Gregory Wilson using a Monte Carlo simulation of ETI's loss history. 677 A statistical distribution was estimated from ETI' s trended loss experience, and the model indicated an average annual loss of $4,890,000. Mr. Wilson excluded losses from Hurricanes Rita, Gustav, and Ike from the model because those losses were securitized and not recovered through the insurance reserve. 678 ETI adds that results from the model simulation were also adjusted by removing any simulated year in which the total storm loss exceeded $100 million, which would likely be securitized. 675 ETI Ex. 19 (McNeal Direct) at 32. 676 ETI Ex. 14 (Wilson Direct) at 5. 677 Id. at Ex. GSW-3. 678 Id. at 9. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 191 PUC DOCKET NO. 39896 The second component of the proposed annual accrual is $3,870,000 per year for 20 years to restore the reserve from the current deficit of $59,799,744 up to the $17,595,000 requested target level. In ETI's opinion, a 20-year period balances the interests of future and past ratepayers. It added that Mr. Wilson's calculations were prepared in accordance with generally accepted actuarial procedures, with certain adjustments to reflect the nature of ratemaking for public utilities. 679 ETI also requests a target reserve of $17 ,595,000. It argues that this would be an actuarially sound provision to cover self-insured losses. ETI noted that the target reserve was also developed by Mr. Wilson through the Monte Carlo simulation based upon the ETI's loss history. 680 Cities recommend maintaining the current target reserve of $15,572,000 and adopting an annual storm damage accrual of $6,150,399. Cities' proposed annual accrual is comprised of two parts: (1) keeping the current accrual of $3,650,000 for projected annual storm expense; and (2) adding $2,500,399 annually to bring ETI's reserve deficit amount, as adjusted by Cities, up to a target reserve of $15,572,000. Cities' witness Jacob Pous testified that the current target reserve of $15,572,000 should be maintained given ETI' s plan to divest itself of the transmission system, which would reduce storm damage expenses. 681 For the same reason, Mr. Pous also stated that the Commission should maintain the current annual accrual amount that was approved most recently in Docket No. 37744.682 According to Cities, ETI witness Wilson acknowledged that his calculations assumed that the current transmission system would be owned by ETI, and if the transmission system were sold, his analysis would need to be adjusted. 683 Cities also note that Mr. Wilson included ETI's 1997 ice storm expenses within the historical storm data used for his calculations. 684 As discussed in 679 ETI Ex. 14 (Wilson Direct) at 11-12. 680 Id. at 9. 681 Cities Ex. 5 (Pous Direct) at 65-66. 682 Id. at 66; see also Docket No. 37744, Final Order at FoF 31 (Dec. 13, 2010). 683 Tr. at 1247. 684 Tr. at 1244-1246. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 192 PUC DOCKET NO. 39896 Section V .F., Cities challenge these expenses. If the Commission determines that those costs should be excluded, Mr. Wilson agreed that it would be inappropriate to include them in his analysis. 685 In addition, Cities stated, Mr. Wilson's Monte Carlo model analysis has been rejected in several cases by the Commission, as noted by Staff witness Chris Roelse. 686 Cities noted that Mr. Wilson limited the storm reserve expense in his model to $100 million, as anything over that amount might be securitized. 687 But, Cities contend, Mr. Wilson did not consider that the storm loss history provided to him by ETI included only storm damage expenses and not capital costs, which are also included when determining the amount capable of being securitized. Thus, in Cities opinion, Mr. Wilson's cap of $100 million was overstated, and for all these reasons Cities argues that Mr. Wilson's analysis should not be considered reliable. Finally, Cities note that ETI requested that the annual storm reserve accrual "would be made . . . only until it reaches the recommended target level, at which point contributions to the reserve would reduce to the lower of annual expected losses or actual losses."688 In Cities view, this request should be rejected and the accrual should only be modified through a future rate case. OPC also recommends adjustments to the storm damage reserve and the annual accrual. As discussed in Section V.F., OPC argues that ETI failed to prove that its storm damage expenses booked since 1996 were reasonable and prudently incurred. Consequently, OPC recommends disallowing all of those charges. Removing those charges would leave ETI with a positive storm reserve balance of $41,871,059, which exceeds the currently approved storm reserve balance of $15,572,000 by $26,299,059. OPC witness Benedict proposed that this surplus be refunded to rate payers at a rate of $1,314,953 per year for 20 years. He also recommended that current annual storm damage accrual of $3,650,000 be maintained, less his proposed customer refund of $1,134,953 per year, leaving a net annual storm damage accrual of $2,335,047 per year. Mr. Benedict acknowledged that some storm damage expenses incurred by ETI since 1996 likely were reasonable and necessary. 685 Tr. at 1246-1247. 686 Staff Ex. 4 (Roelse Direct) at 12. 687 ETI Ex. 14 (Wilson Direct) at 9. 688 ETI Initial Brief at 151. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 193 PUC DOCKET NO. 39896 Therefore, as an alternative proposal, Mr. Benedict suggested that ETI's current storm balance reserve be set at the last approved amount of $15,572,000 (i.e., without any surplus or deficit) and that the currently approved total annual accrual of $3,650,000 be maintained. In addition, OPC argues that Mr. Wilson's Monte Carlo model analysis was flawed because it included expenses that ETI did not establish were reasonable and prudently incurred.689 Staff witness Chris Roelse agreed that ETI's proposed target reserve of $17,595,000 is reasonable. However, he recommended an annual accrual of $8,270,000, which is $490,000 less than ETI' s request. Mr. Roelse pointed out that ETI' s witness calculated the proposed annual accrual based on a Monte Carlo simulation, which projects a loss experience over a longer time than the period captured in the available loss history. However, Mr. Roelse stated, the Commission has not approved the use of these models in prior dockets; instead, it has relied on averaging known insurance losses over a period of time to compute the annual accrual. Using historical loss data, Mr. Roelse calculated an annual expected storm loss of approximately $4,400,000. When this amount is added to the proposed annual accrual of $3,870,000 to restore the reserve balance from its current deficit, it produces a total annual accrual of $8,270,000, which Staff recommends.690 In response, ETI agreed that if portions of the underlying costs upon which the Monte Carlo analysis was performed are removed from the reserve, then the outcome of Mr. Wilson's analysis would be different. However, ETI stressed that questions about the underlying expenses are not an attack on the Monte Carlo analysis itself. Rather, Mr. Wilson provided an analysis based upon information supplied by ETI, and he did not claim to support the expenses themselves. But ETI disagreed with the challenges to the underlying costs, as discussed in Section V.F. 691 Most of Cities' and OPC's objections to ETI's requested storm damage annual accrual and target reserve relate to their objections to the underlying expenses, as discussed in Section V .F. For the reasons stated in that section, the AUs denied those objections, and they do not support rejecting 689 OPC Ex. 6 (Benedict Direct) at 6-16; OPC Initial Brief at 14-20; OPC Reply Brief at 13-15. 690 Staff Ex. 4 (Roelse Direct) at 10-15; Staff Initial Brief at 13-14. 691 ETI Reply Brief at 81. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 194 PUC DOCKET NO. 39896 ETI' s request for the annual accrual or target reserve. Likewise, the AUs find that Cities' concerns about ETI selling its transmission system are too uncertain to justify altering the storm damage reserve at this time. Cities also raised a question about whether Mr. Wilson properly calculated the cap he used to exclude from his analysis storms that would likely result in securitized costs. Staff pointed out that the Commission has not approved the use of the Monte Carlo simulation model in prior dockets. Rather, the Commission has traditionally used known insurance losses over a period of time. The AUs note that neither PURA nor the Commission's rules either require or prohibit the use of actuarial models, such as the Monte Carlo simulation. The prior dockets cited by Staff did not adopt the recommendations developed by actuarial models, but the Commission also did not expressly reject the models in those cases. Likewise, however, ETI has not cited any Commission decisions that expressly adopted or used such models. Staff witness Chris Roelse explained that the Commission has traditionally averaged known insurance losses over a period of time to compute the annual accrual. He made such a calculation that produced an annual accrual for storm damage loss of $4,400,000. When added to the proposed annual accrual of $3 ,870,000 to restore the reserve balance from its current deficit, the total annual accrual equals $8,270,000. No party challenged that calculation. Because a question remains as to whether Mr. Wilson properly calculated his cap to exclude storm damage expenses that would likely be securitized, the AUs find it is more reasonable to adopt the annual accrual proposed by Staff. Therefore, the AU s recommend that the Commission approve a total annual accrual of $8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual accrual of $3 ,870,000 for 20 years to restore the reserve from its current deficit. The AU s also recommend approval of ETI' s proposed target reserve of $17 ,595,000. Finally, the AU s recommend that the Commission require ETI to continue recording its annual accrual until modified by an order in a future rate case, as requested by Cities. Otherwise, ETI could continue to receive rates based on the total accrual amount, but not record the receipts in the storm damage reserve. The AUs find that such circumstances would not result in just and reasonable rates. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 195 PUC DOCKET NO. 398% L. Spindletop Gas Storage Facility Cities challenged ETI' s use of the Spindletop Facility, arguing that the costs of operating it outweigh the benefits gained from it. In Section V.H., the AI.Js rejected Cities' contention that a substantial portion ofETI's annual costs to operate the Spindletop Facility should be removed from ETI' s rate base. For the same reason he challenged the Spindletop Facility costs associated with rate base, Cities witness Nalepa also challenges a portion of ETI' s costs derived from the Spindletop Facility that are associated with operating expenses. Specifically, Mr. Nalepa and Cities argue that $2,090,116 (consisting of $309,751 in depreciation expense and $1,780,365 associated with the Spindletop Facility) ought to be removed from ETI' s operating expenses. 692 For the same reason that they rejected Cities' Spindletop Facility arguments relevant to rate base, the AI.J s also reject Cities' Spindletop Facility arguments relevant to operating expenses. VIII. AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue No. 3] PURA requires that more stringent standards be applied to affiliate expenses than are applied to other utility company expenses. Section 36.058 begins by stating "except as provided by Subsection (b),"the PUC may not allow as capital cost or as expense a payment to an affiliate for the cost of a service, property, right, or other item or interest expense. Subsection 36.058(b) provides that the Commission may allow an affiliate payment "only to the extent" that the PUC finds the payment is reasonable and necessary for each item or class of item as determined by the Commission. The seminal case interpreting PURA' s affiliate transaction standard under Section 36.058 is Railroad Commission v. Rio Grande Valley Gas Company. 693 In that case, the court recognized that PURA' s affiliate transaction statute created a presumption that a payment to an affiliate is unreasonable. The court explained: 692 Cities Ex. 6 (Nalepa Direct) at 19; Cities Initial Brief at 76. 693 683 S.W. 2d 783 (Tex. App.-Austin 1985, no writ). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 196 PUC DOCKET NO. 39896 Rio's entire approach has been that the Commission is required to allow the residual affiliate charges unless they are shown to be imprudent, unreasonable, or out of line. Although this may be true with respect to arms length transactions, it is not true with respect to affiliates about which the Legislature has its suspicion and which to any reasonable mind are clearly tainted with the possibility of self-dealing. The court went on to state that the burden was upon Rio to show that its affiliate charges were just and reasonable. The court interpreted the PURA affiliate transaction statute and explained four major areas in which Rio had failed to meet its burden of proof: • Plaintiff had the burden of showing that the prices it was charged by its affiliate were no higher than the prices charged by the supplying affiliate to its other affiliates .... • Plaintiff had the burden of showing that expenses which may not be allowed for rate making purposes for any reason ... were not included in the "allocated expenses." ... • Plaintiff had the burden of proving that each item of allocated expense was reasonable and necessary.... • Plaintiff had the burden of proving that the allocated amounts reasonably approximated the actual cost .of services to it. ... fu 2000, the Third Court of Appeals once again spoke on the issue of affiliate transactions in the utility setting. fu Central Power and Light Company/Cities of Alice v. Public Utility Commission, the court cited to Rio Grande Valley Gas Company and stated: Because of the possibility for self-dealing between affiliated companies, however, expenses paid to an affiliated entity are presumptively not included in the rate base. A utility can overcome this presumption against affiliate expenses only if it demonstrates that its payments are 'reasonable and necessary for each item or class of 694 items as determined by the commission. ' PURA Section 36.058 places a greater burden of proof on the utility to prove the reasonableness and necessity of its affiliate transactions because of the nature of the relationship between the utility and its affiliates. These transactions are not considered to be arms-length, and there is a potential for 694 36 S.W.3d 547 at 564 (Tex. App.-Austin 2000, pet. denied) (citations omitted). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 197 PUC DOCKET NO. 39896 self-dealing. The transactions must be disallowed for regulatory purposes, unless the utility presents sufficient evidence that it has met each of the affiliate transaction statutory requirements. If the regulatory tests for affiliate transactions are not properly enforced, the regulated utility may become a vehicle for cross-subsidization by ratepayers of other regulated or unregulated affiliates. OPC witness Szerszen was the only witness to challenge ETI's affiliate transactions, 695 recommending a total affiliate disallowance (after erratas) of $8,945 ,221. 696 Dr. Szerszen reviewed a select subset of ETI' s affiliate expenses using the PURA affiliate transaction standards. She reviewed the Company's affiliate transactions on a project by project basis, noting that such a review was more efficient and easier to understand. 697 Dr. Szerszen testified that a review by the Company's 25 classes of service presents a far too macro view of affiliate transactions that does not allow an adequate review of ETI' s affiliate transactions according to PURA mandates and takes the focus away from the important issues. 698 OPC notes that PURA Subsection 36.058(f) requires that if the Commission finds an affiliate expense for the test period to be unreasonable, then the Commission is to make a determination of what level of the expense is reasonable. By analyzing ETI' s affiliate transactions on a project basis, OPC contends that it has facilitated the Commission's ability to make such a determination for each of ETI' s classes of service; instead of an "up or down" decision on the macro level of expense for the class, the Commission can disallow the portion not shown to be reasonable and approve the remainder as reasonable. 695 Cities witness Mark Garrett recommended disallowance of certain short-term incentive compensation affiliate costs, but those disallowances are largely also recommended by Dr. Szerszen. See ETI Ex. 69 (Tumminello Rebuttal) at 17. ETI contends that the duplicated disallowances by Dr. Szerszen and Mr. Garrett would result in double counting $217 ,520 of the requested affiliate charges and requests that if the AUs rule in OPC' sand Cities' favor regarding these short-term incentive compensation costs, that disallowance should be reduced by $217,520. ETI Initial Brief at 157, n. 898. 696 Tr. at 1607. 697 OPC Exhibit No. 1 (Szerszen Direct) at 42-43. 698 OPC Exhibit No. 1 (Szerszen Direct) at 42-43; Tr., at 1671-72. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 198 PUC DOCKET NO. 39896 ETI disagrees with OPC's contentions and argues that Dr. Szerszen's approach to addressing the Company's affiliate case is inappropriate for a number of reasons and should be rejected. • First, her approach is directly contrary to the Commission's Guiding Principles included as part of the Commission's Transmission and Distribution Cost of Service Rate Filing Package that was issued on April 2, 2003. 699 Item 2 of the Guiding Principles clearly states that a class of service approach is required for purposes of complying with the provisions of Section 36.058 of PURA. 700 Dr. Szerszen ignores the class of service approach required by Section 36.058 of PURA as detailed in the Guiding Principles, and instead states OPC' s case on a project code-by- project code basis. • Second, Dr. Szerszen's approach is directly contrary to the Commission's directives in Docket No. 16705. In that docket, the Commission disallowed a substantial amount of affiliate expense because Entergy Gulf States, Inc. had done then what Dr. Szerszen proposes here - based the affiliate analysis solely on project codes, rather than affiliate classes of service. Because the Commission found that a scope statement/project code-based affiliate analysis is "impossible," the Company, in its subsequent base rate cases, including its filing in this docket, changed to a class-based presentation, as directed by the Commission. • Third, by refusing to consider a class-based analysis, Dr. Szerszen has ignored the Company's testimony, presented by 19 affiliate witnesses, which explains in detail why the Company's affiliate-incurred costs meet the Section 36.058 of PURA and Rio Grande standards. 701 According to ETI, the Company's affiliate class witnesses, who are knowledgeable about the activities that are encompassed in each of their classes, have each shown why the services provided through those classes are necessary. They have each also addressed numerous Commission-recommended metrics to measure the reasonableness of costs, including cost trends, staffing trends, the budgeting process, and, if applicable, benchmarking and outsourcing comparisons. 702 Their testimony and exhibits, according to ETI, show numerous different "views" of the costs in their classes, including the project codes that comprise their classes. Each affiliate witness also addressed the "not higher than" and "reasonably approximates cost" standards applicable to affiliate costs. ETI contends that the evidence provided by its witnesses meets the requirements of these Guiding Principles and supports the Company's burden of proof for the recovery of affiliate costs. ETI also contends that Dr. Szerszen ignores this overwhelming 699 See ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-1. 700 Dr. Szerszen conceded that the Guiding Principles require that a utility's affiliate case be presented in a sufficient number of class or other logical groupings. Tr. at 1632. 701 Dr. Szerszen claimed that, instead of considering the narrative class testimony, she instead "looked at more of the detail," presumably meaning the exhibits. Tr. at 1629. 702 ETI Ex. 69 (Tumminello Rebuttal) at Ex. SB T -R-1. Dr. Szerszen conceded that the Company's testimony included proof items such as benchmarking data, outsourcing, staffing trends, and cost trends. Tr. at 1631. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE 199 PUC DOCKET NO. 39896 evidence and the careful attention paid to presenting it in an organized manner. In addition, she presents no evidence in accordance with the Guiding Principles that supports her proposed disallowances. • Fourth, the Company's case is much less cumbersome and less complex than the approach suggested by OPC, which would require a showing on the necessity, reasonableness, "not higher than," and "reasonably approximates cost" standards for each of almost 1,300 project codes subject to this docket. Even if the Company were to do that, Dr. Szerszen's "cherry picking" approach among the project codes ignores any savings in other project codes that would comprise a class of affiliate costs, thereby resulting in an overall reasonable level of costs within the class even assuming that any of her complaints about individual project codes had merit. • Fifth, ETI contends that Dr. Szerszen fails to mention Section 36.058(f) of PURA, which requires that the Commission determine the reasonable level of "an affiliate expense" if it first finds that the expense presented is unreasonable. But rather than offering an alternative "reasonable" level of an expense"", she either categorically disallows all costs in that project; or, in some instances, substitutes an arbitrary sharing or allocation of costs between ETI and its regulated affiliates, or ETI and its non-regulated affiliates. In doing so, Dr. Szerszen does not make any evidence-based attempt to ground her alternative allocation (and associated disallowance of ETI affiliate costs) on any objective basis reflecting cost causation principles. ETI contends that the effect of her approach is to presume that the Company needs zero dollars in its cost of service to perform a variety of essential utility support activities. • Sixth, Dr. Szerszen' s positions in the 2009 Oncor rate case,703 which she agrees are similar to her positions in this ETI base rate case, 704 were rejected by the two SOAH AU s and the Commission in that docket. ''Many of the allegations and arguments made by Dr. Szerszen in this case are very similar, if not identical, to the points she asserted in the Oncor case. The AU s agree that the Commission's Guiding Principles set forth the minimum that a utility must present to establish a prima facie case, and it is clear that ETI met that burden. That, however, is not the end of the question. Permitting a utility to escape further scrutiny of its affiliate transactions by resting on its prima facie presentation imposes too many limits and, as suggested by OPC, presents too macro a view to be a legitimate review for rate case purposes. 703 Application of Oncor Electric Delivery Company, LLC for Authority to Change Rates, Docket No. 35717 (PFD issued on Jun. 2, 2009; Order on Rehearing issued on Nov. 30, 2009) (Oncor). 704 Tr. at 1656. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE200 PUC DOCKET NO. 39896 OPC performed essentially a sample review of ETI' s affiliate transactions. The review was not exceptionally large, and (as evidenced by ETI' s concurrence in the removal of some of the costs) it represented an additional layer of review to ensure that improper costs would not inadvertently be charged to ratepayers. That, of course, is not the sole focus of OPC' s review, but it is important for purposes of determining whether the review itself is appropriate. If intervenors and Staff were limited to the macro level of review urged by ETI, such matters would never be revealed and there would exist a possibility that ratepayers would be charged for matters not their responsibility. The ALJs do not characterize OPC's review as "cherry picking." It is more a reasonable sample for examination that gives ETI a reasonable opportunity to explain the reasons for the charges to ratepayers. Accordingly, the ALJs find that the Commission's Guiding Principles do not limit the review performed by OPC, and the review performed by OPC is not contrary to the Commission's holdings in Docket No. 16705. A. Large Industrial & Commercial Sales Reallocation OPC contends that ETI incurs considerable amounts of sales and marketing expenses that are exclusively for the benefit of the larger commercial and industrial customers. However, most of ESI' s sales, marketing, and customer service expenses are allocated to residential and small business customers. 705 The vast majority of the sales, marketing and customer service expenses are allocated to the operating companies based on customer counts, the majority of these expenses are consequently allocated to residential and small business customers. In the test year, residential and small general service customers made up 94.8 percent of the ETI total customer count. ETI' s General Service, Large General Service, and Large Industrial Power Service, and Lighting classes combined comprise only 5.2 percent of ETI' s customers. For the test year, OPC argues that ETI is requesting the recovery of $2.086 million of sales, marketing, billing and load research expenses that benefitted only the large customer service classes. OPC contends that it is inappropriate for residential and small customers to pay for these expenses, when cost causation is so readily identifiable, particularly since a disproportionately small portion of larger customer sales and 705 OPC Ex. l (Szerszen Direct) at 45. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE201 PUC DOCKET NO. 39896 marketing expenses is allocated to ETI's largest customers. 706 The total recommended reallocated large customer expense is $2,086,145. ETI and TIEC oppose OPC' s recommendation, arguing that it is "cherry-picking" and that the evidence does not demonstrate that the $2.086 million of affiliate expense should be directly assigned to the large commercial and industrial classes. 707 With respect to the first argument, ETI and TIEC contend that Dr. Szerszen developed her adjustment by examining a limited sample of affiliate project code summaries and making the call, based on project code descriptions, that certain affiliate costs for marketing, sales and customer service expense should be directly assigned to large commercial and industrial customers. 708 Both TIEC and ETI contend that the bias and results-oriented nature of her recommendation became apparent when Dr. Szerszen admitted on cross examination that she made no effort to examine whether certain affiliate costs should be directly assigned to residential and small customers.709 Both ETI and TIEC contend that it is inappropriate to take a "limited sample of costs" and directly assign them to a particular class. According to TIEC, Dr. Szerszen admitted that it could have been appropriate to make an adjustment for direct assignment of costs to small commercial and residential customers based on principles of cost causation. 710 However, she made no effort to do that herself, nor did she ask ETI to conduct such an analysis. 711 The parties argue that the evidence shows that Dr. Szerszen's recommendation rests on an incomplete analysis of ETI's affiliate costs and her recommendation should be rejected because direct assignment of costs is only appropriate if there has been a thorough 106 OPC Ex. 1 (Szerszen Direct) at 45. 707 ETI Ex. 55 (LeBlanc Rebuttal) at 5; TIEC Ex. 3 (Pollock Cross Rebuttal) at 36. 708 Tr. at 1609. 709 Tr. at 1609-10. 710 Tr. at 1685. rn Tr. at 1613-1624. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE202 PUC DOCKET NO. 39896 and complete cost study analysis to determine what costs are or are not appropriate for direct assignment to all of the classes. TIEC further argues that the evidence did not demonstrate that the $2.086 million of affiliate expense that Dr. Szerszen proposes for direct assignment to large commercial and industrial customers is solely attributable to costs caused by those customers. Mr. Pollock testified that the project codes Dr. Szerszen selected include load research expenses that benefit residential and small commercial customers. 712 TIEC pointed out that ETI witness Stokes testified that the billing methods used for the affiliate expenses for customer service operations and retail operations were fair and reasonable.713 According to TIEC, Dr. Szerszen's proposal should be rejected because her assertion that these expenses exclusively benefit large commercial and industrial customers is incorrect. The AU shave reviewed the arguments of the parties and find that Dr. Szerszen' s analysis is far from complete. It appears to be result-oriented, ignoring critical aspects (such as failing to make an adjustment for direct assignment of costs to small commercial and residential customers based on principles of cost causation). The AUs believe that Dr. Szerszen's analysis with respect to this issue should not be adopted. B. Administration Costs Dr. Szerszen recommended disallowance of $94,709 (25 percent) of the charges in Project F3PCFACALL, contending that ESI failed to directly charge any of the costs in this project code to ETI. She claimed that the billing method applied to this project code by ESI (that is, Billing Method "SQFALLC"), which is based on square footage, is not appropriate for these types of 714 costs. 712 TIEC Ex. 3 (Pollock Cross Rebuttal) at 35. 713 ETI Ex. 66 (Stokes Rebuttal) at 3. 714 OPC Ex. l (Szerszen Direct) at 80-82. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE203 PUC DOCKET NO. 39896 ETI witness Plauche explained that the costs captured in this project code are primarily for the oversight of administrative functions, such as facilities, real estate, and security.715 This project code applies to the administration of these types of functions. These services benefit all companies that receive facility services and are not attributable to any one specific Entergy affiliate. Therefore, it is appropriate to bill these costs to all companies based on their pro rata share of square footage occupied. 716 The AUs concur that this is the appropriate method to employ and, therefore, recommend that the Commission approve the inclusion of these costs as requested by ETI. C. Customer Service Operations Class Dr. Szerszen recommended disallowances in seven project codes covered primarily by ETI' s Customer Service Operations Class: (1) F3PCR29324 (Revenue Assurance - Adm.) for a disallowance of $70,849; (2) F3PCR53095 (Headquarter's Credit & Collect) for a disallowance of $110,338; (3) F3PCR73380 (Credit Systems) for a disallowance of $73,562; (4) F3PCR73458 (Credit Call Outsourcing) for a dis allowance of $197; (5) F3PCR73381 (Customer Svc Cntr Credit Desk) for a disallowance of $43,378; (6) F3PCR73390 (Customer Svs Ctl - Entergy Bus) for a dis allowance of $60, 926; and (7) F3 PCR73403 (Customer Issue Resolution - ES) for a dis allowance of $1,869. 717 1. Projects F3PCR29324 (Revenue Assurance· Adm.), F3PCR53095 (Headquarter's Credit & Collect), F3PCR73380 (Credit Systems), and F3PCR73458 (Credit Call Outsourcing) For the costs captured by these project codes, Dr. Szerszen recommended that the costs be reallocated based on the Company's 10 percent "bad debt" expense percentage. 715 ETI Ex. 20 (Plauche Direct) at 15-26. 716 ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-2 at 10. 717 OPC Ex. l (Szerszen Direct) at 76-78. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE204 PUC DOCKET NO. 39896 ETI witness Stokes responded that the costs captured by these project codes are for management and supervision of credit, collection, and revenue assurance activities for all of the Operating Companies. These functions ensure the most efficient processes are used in managing write-offs for all the Operating Companies and have contributed to Entergy' s first quartile ranking in benchmarking of credit and collection operations. These managerial and supervisory costs, which include bankruptcy administration, surety administration, arrears management, collection agency administration, skip tracing, and final bill collections, remain consistent whether ETI's bad debt percentage is 10 percent, 30 percent, or any other percent and are appropriately allocated using the CUSTEGOP billing method, which is based on the number of electric and gas customers for each Operating Company. 718 ETI has provided credible evidence that it has chosen the correct billing methodology. Therefore, the Al.Js recommend the Commission approve inclusion of these costs as requested by ETI. 2. Projects F3PCR73381 (Customer Svc Cntr Credit Desk), F3PCR73390 (Customer Svs Ctl • Entergy Bus), and F3PCR73403 (Customer Issue Resolution - ES) Dr. Szerszen recommended that these costs be reallocated using the CUSTCALL billing method. Given ESI's demonstrated tracking capabilities, Dr. Szerszen reallocated the costs of this project using a 10.8 percent customer call allocator, which is on the low end of the 10.70 percent-11.04 percent Test-Year CUSTCALL allocators. 719 ETI witness Stokes believes that Dr. Szerszen' s proposed reallocation is arbitrary and fails to consider the cost causation associated with the actual project code at issue. These costs are not driven by a specific proportion of calls from each Operating Company (that is, by the CUSTCALL allocator). The costs captured by Project F3PCR73345 reflect the costs of overseeing the Quick 718 ETI Ex. 66 (Stokes Rebuttal) at 15-16. 719 OPC Exhibit No. l (Szerszen Direct) at 77 and 118; OPC Exhibit No. 27 (ETI's Ex. SBT-15, Attachment 6) at 2; Tr., at 838-839. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE20S PUC DOCKET NO. 39896 Payment Center vendors in each of the Entergy Operating Companies, regardless of the number of calls by customers to the Company. The ALls are persuaded that the allocation methodology chosen by ETI is the superior method and that the CUSTCALL allocator would not be appropriate given the cost causation associated with the project. Accordingly, the ALls recommend the Commission approve the costs proposed by ETI. D. Distribution Operations Class Dr. Szerszen addressed three project codes that are within the Distribution Operations Class: (1) F5PCDW0200 (Lineman's Rodeo Expenses) for adisallowanceof $7; (2) F3PCTJGUSE(Joint Use With Third Party E) for a disallowance of $6,405; and (3) F3PCTJTUSE (Joint Use With 3rd Parties -A) for a disallowance of $36,293. 720 1. Project F5PCDW0200 (Lineman's Rodeo Expenses) Dr. Szerszen claimed that the expenses captured by this project should be disallowed because ETI is a monopoly and Texas ratepayers should not have to pay for corporate image costs. ETI witness Tumminello responds, stating that this minimal amount is related to a safety competition known as the "Lineman's Rodeo," it is not a corporate "image" expense. The cost, according to Ms. Tumminello, is driven by Entergy employee safety in the Distribution business units. 721 The AI.Js agree that the Lineman's Rodeo competition is not a corporate image expense, rather it is designed to promote employee safety. The AI.Js recommend the Commission approve inclusion of the costs captured by this project as requested by ETI. 720 OPC Ex. 1 (Szerszen Direct) at 66, 75. 721 ETI Ex. 41 (Tumminello Direct) at Ex. SBT-E at 1234. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE206 PUC DOCKET NO. 39896 2. Projects F3PCTJGUSE (Joint Use With Third Party- E) and F3PCTJTUSE (Joint Use With Third Parties - A) Dr. Szerszen recommends exclusion of these two projects, which she claims represent the difference between the costs incurred for ETI for pole rental costs and the revenues received from pole space rentals. With respect to this proposed disallowance, ETI witness McCulla states that Dr. Szerszen has confused the rental of space on transmission poles and the rental of space on distribution poles. She has essentially performed a cost-benefit analysis that erroneously compares the cost of providing rental space on distribution poles with the income received solely from rental of space on transmission poles. Mr. McCulla explained that data for the distribution poles show that the more than $2.5 million in revenues from distribution pole rentals far exceeds the $67, 174 in costs billed to ETI under these two project codes and, therefore, Dr. Szerszen's misassumption that the revenues were less than the costs incurred is unfounded. 722 The AU s find that Dr. Szerszen erred. Making the correct comparison, as demonstrated by Mr. McCula, shows there is no basis for the disallowance claimed by Dr. Szerszen. The ALls, therefore, recommend the Commission deny the requested disallowance. E. Energy and Fuel Management Class Dr. Szerszen addresses seven project codes that are within the Energy and Fuel Management Class: (1) F3PCCSPSYS (System Planning And Strategic) for a disallowance of $29,304; (2) F3PCWE0140 (EMO Regulatory Affairs) for adisallowance of $114,468; (3) F3PPSPE002 (SPO 2009 Renewable RFP Expense) for a disallowance of $3,014; (4) F3PPSPE003 (SPO Summer 2009 RFP Expense) for a disallowance of $56,672; (5) F3PPSPE004 (SPO Summer09RFP IM&Propslsubmt) for a disallowance of $42,018; (6) F3PPWET300 (SPO 2008 Western Region 722 ETI Ex. 59 (McCulla Rebuttal) at 8-12. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE207 PUC DOCKET NO. 39896 RFP-Te) for a disallowance of $645; and (7) F3PPWET303 (SP02008WinterWestnRegionRFP-IM) for a disallowance of $4,200. 723 1. Project F3PCWE0140 (EMO Regulatory Affairs) Dr. Szerszen testified that Texas ratepayers do not receive benefits as a result of the costs captured by this project code and should therefore not be charged those costs. 724 ETI witness Cicio explained that Dr. Szerszen misinterpreted an RFI response to conclude that Texas ratepayers did not receive benefits from the activities whose costs were booked through this project code. That project code is not intended to capture costs for docketed or large System Planning and Operations projects. Mr. Cicio states that it is not possible to assign a specific project code for every discrete activity performed by each employee, nor would it be appropriate to attempt to do so. Regardless of the number of activities specifically identified through project codes, there will remain the need to have generic project codes that capture time spent on more general, undocketed matters and activities that are no less beneficial to ratepayers. 725 The AU s agree that Texas ratepayers receive benefits as a result of the costs charged to this account. Accordingly, the AUs recommend the Commission approve inclusion of the costs as requested by ETI. 2. Projects F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE004 (SPO Summer09RFP IM & Propslsubmt), and F3PPWET303 (SP02008 Winter Westn RegionRFP-IM) Dr. Szerszen testified that the costs captured by these projects should be disregarded because they were incurred during the 2008-2009 period, which is outside of the Test Year, and are nonrecurring. 726 723 OPC Ex. l (Szerszen Direct) at 55, 60, and 65-66. 724 Id. at 55. 725 ETI Ex. 45 (Cicio Rebuttal) at 8-9. 726 OPC Ex. I (Szerszen Direct) at 65. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE208 PUC DOCKET NO. 39896 ETI witness Cicio explained that although these projects were initiated prior to the Test Year, the costs that the Company seeks to recover through these project codes were expenses incurred during the Test Year, including development activities, request for proposal issuance, bidders conferences, written and posted questions and answers from market participants and other interested parties, submission of proposals, screening of proposals, proposal evaluation, follow-up questions and clarifications, recommendations and awards, contract negotiations, Independent Monitor reports, and regulatory approvals, if necessary. These routinely encompass a multi-year time frame, and the costs required to perform those activities, although associated with a project that may have been initiated several years previously, are properly incurred over the life span of the project. He also states that they are recurring because they reflect the kinds and levels of charges that would be expected to be incurred on an ongoing basis in association with requests for proposals managed by ESI on behalf of the Entergy Operating Companies, and the Company has been involved in these types of solicitations since 2002. 727 The AlJs find that the costs captured by these projects were incurred during the Test Year and represent the kinds and levels of costs routinely incurred on a recurring basis. Accordingly, the AU s recommend that the Commission approve their inclusion as requested by ETI. 3. Project F3PCCSPSYS (System Planning and Strategic) Dr. Szerszen recommended total disallowance of the costs captured by this project code because they are allocated based on the total assets of the Entergy affiliates. 728 Dr. Szerszen' s conclusion appears to be that no such corporate-level costs should be allocated to ETI because there are other project codes that allocate corporate planning and analysis-type costs only to the regulated utilities, such as ETI; thus, any corporate-level costs that are allocated to all subsidiaries, whether regulated or non-regulated, should not be charged to ETI. 727 ETI Ex. 45 (Cicio Rebuttal) at 13-14. 728 OPC Ex. 1 (Szerszen Direct) at 60-61. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE209 PUC DOCKET NO. 39896 ETI witness Tumminello testified that Dr. Szerszen's theory neither considers the Entergy organization as a family of companies and ETI' s place in that family, nor the fact that these services are not only relevant to ETI as part of the Entergy family, but are reasonable, necessary and meet the Commission's affiliate cost recovery standard. ESI's corporate oversight services are provided to both individual companies and groups of companies within the Entergy 'corporate structure. As a member of the corporate group, ETI receives the benefit of corporate-level planning, reporting, and forecasting activities provided by ESI. 729 The ALls find that ETI (and, therefore, its ratepayers) does receive benefits as a member of the Entergy family of companies and that it is appropriate for it to receive charges for those services. Therefore, the AUs recommend the Commission approve the inclusion of costs as requested by ETI. F. Environmental Service Class Dr. Szerszen recommended disallowance of $301,879 in six project codes primarily within ETI's Environmental Services Class: (1) F3PCCE0129 (Corporate Sustainability Strat) for a disallowance of $6,781; (2) F3PCCE0193 (Corp Environmental Special Pro) for a disallowance of $1,203; (3) F3PCCEIE01 (Corp Environmental Initiatives) for a disallowance of $2,413; (4) F3PCCEll01 (Corp Environmental Initiatives) for a disallowance of $2,413; (5) F3PCCEP001 (Corporate Environmental Policy) for a disallowance of $269,248; and (6) F5PPBCNAVF (Avian Flu Contingency Planning) for a disallowance of $47. 730 Dr. Szerszen' s reasoning for this disallowance was that these six project codes, which all deal with corporate environmental policy, initiatives, strategy, and consulting services, were allocated based on Billing Method CAPAOPCO, which is based on the fossil plant capacity of the regulated utility operating companies, even though "non-regulated entities clearly benefit from the corporate level expenses."731 Dr. Szerszen recommended a $47 disallowance for Project F5PPCCNAVF 729 ETI Ex. 69 (Tumminello Rebuttal) at l 0-11. 730 OPC Ex. 1 (Szerszen Direct) at 62-63. 131 Id. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE210 PUC DOCKET NO. 39896 (Avian Flu Contingency Planning), asserting that this charge is a "corporate imaging expense that should not be borne by Texas ratepayers."732 According to ETI, Dr. Szerszen has a fundamental misunderstanding of how the affiliate billing system works and, as a result, she incorrectly assumed that ESI charges are not being properly allocated. ETI argues that the non-regulated Entergy affiliates do receive the proper and appropriate allocation of costs. The two service companies for non-regulated affiliates also provide services to their non-regulated affiliates directly. There simply is no subsidization or improper allocation. 733 Dr. Szerszen noted that Entergy' s website indicates that nuclear-related environmental issues are being pursued. 734 She argued that this shows that the non-regulated affiliates are under-allocated environmental-related costs. Ms. Stokes explained that the project codes at issue "deal with services provided to the operating companies .... and just looking at the website there are other things ... that are not covered or paid for by Texas ratepayers in these project codes that are in this 735 testimony." Therefore, according to Ms. Stokes, these project codes are not allocated in such a way that under-recovers costs from the non-regulated affiliates; they pay their own way. Finally, the Project Summary for the Avian Flu Contingency Planning project shows that these costs involve developing and communicating Avian Flu business continuity plans and then maintaining, checking, and adjusting those plans once established. 736 These are not "corporate imaging expenses" as characterized by Dr. Szerszen. 732 Id. at 66. 733 See, e.g., ETI Ex. 41 (Tumminello Direct) at 10-15. Moreover, while ESI bills the regulated utility affiliates such as ETI at cost, it bills the non-regulated affiliates at cost plus a 5 percent mark-up pursuant to a June 1999 Securities and Exchange Commission order. ETI Ex. 41 (Tumminello Direct) at 15. This 5 percent mark-up is then flowed back to entities that receive service from ESL Therefore, the regulated affiliates are, by federal order, receiving essentially a rebate from the non-regulated affiliates. 734 OPC Ex. 1 (Szerszen Direct) at 62. 735 Tr. at 884. 736 ETI Ex. 41 (Tumminello Direct) at SBT-E at 1342-43. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE211 PUC DOCKET NO. 39896 The AU s agree that ETI' s evidence demonstrates the recoverability of the costs captured by these project codes. Therefore, the ALJs recommend the Commission approve their recovery. G. Federal PRG Affairs Class Dr. Szerszen recommended disallowances for three project codes primarily in the Federal PRG Affairs Class: (1) F5PPSPE044 (PMO Support Initiative-System) for a disallowance of $344; (2) F3PPUTLDER (Utility Derivatives Compliance) for a disallowance of $20,447; and (3) F3PCSYSRAF (System Regulatory Affairs-Federal) for a disallowance of $352,084.737 1. Project FSPPSPE044 (PMO Support Initiative-System) Dr. Szerszen recommended disallowance of $344.29 from Project F5PPSPE044 (PMO Support Initiative System). ETI responds, however, that a review of the Project Summary for that project code in Ex. SBT-E reveals that ETI already removed those costs before even filing its direct case. Therefore, according to ETI, Dr. Szerszen is recommending disallowance of a cost that is not in this case.738 The AU s agree that examination of the exhibit referenced by ETI appears to reveal that the costs challenged by Dr. Szerszen have been removed from this case through a pro Jonna adjustment. Accordingly, the ALJs recommend the Commission reject OPC's challenge. 2. Project F3PPUTLDER (Utility Derivatives Compliance) Dr. Szerszen recommended disallowance of $20,447 of derivatives expenses because ETI did not use derivative instruments and therefore should not be charged these costs and because ratepayers do not benefit from derivatives. 739 737 OPC Ex. 1 (Szerszen Direct) at 46-47, 66-67. 738 ETI Initial Brief at 174-175. 739 ETI stated that it assumes that Dr. Szerszen must be referring to Project Code F3PPUTLDER (Utility Derivatives Compliance) because her recommended disallowance is the same total ETI adjusted amount shown SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE212 PUC DOCKET NO. 39896 ETI witness Tumminello responded that Project F3PPUTLDER was charged by a group developing compliance mechanisms to protect Entergy' s regulated utility interests in observance of the Dodd-Frank Act. Although ETI does not currently use any derivative activities, understanding the impacts of that Act is necessary to ensure current and future compliance through Entergy. The definitions under the legislation have not been finalized, and there remain issues that ETI must be aware of to fully comply. These costs, therefore, are necessary and reasonable charges that should not be disallowed. 740 The explanation offered by ETI for the inclusion of these charges appears reasonable to the AU s. Even though ETI does not now use derivatives, it is possible that it will in the future and it is important that it be aware of the regulatory framework associated with such actions to avoid problems. The AU s therefore recommend the Commission approve inclusion of these costs as requested by ETL 3. Project F3PCSYSRAF (System Regulatory Affairs-Federal) In the regulatory affairs category, ETI requests the recovery of various legal, testimony-related, communications, and filing costs associated with both Texas-specific regulatory activities, FERC-related regulatory activities, and non-Texas specific regulatory activities. OPC witness Szerszen did not recommend a disallowance of the $1,442,223 in adjusted Test Year expenses for regulatory affairs that ETI has shown to be specific to the Texas jurisdiction. 141 Rather, Dr. Szerszen recommended that all regulatory affairs expenses not specific to Texas be disallowed.7 4 2 These expenses total $759,868.743 on the Project Summary for that project code. See SBT-E at 1113. The ALJ s make the same assumption as it appears reasonable. 740 ETI Ex. 69 (Tuminello Rebuttal) at Ex. SBT-R-2 at 3. 741 See OPC Ex. 3 (Szerszen Workpapers) at 368-371. 742 OPC Ex. 1 (Szerszen Direct) at 46-47. 743 Id. at 46. SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE213 PUC DOCKET NO. 39896 Project F3PCSYSRAS (System Regulatory Affairs - State) was incurred for administrative activities for senior management, project work associated with system-wide regulatory matters, system-wide regulatory strategies and emerging regulatory issues, and it relates to multiple regulated jurisdictions. 744 Project No. F3PCSYSRAF (System Regulatory Affairs - Federal) was incurred for regulatory oversight and coordination of FERC matters. 745 OPC contends that ETI provided no evidence that Texas ratepayers receive any tangible benefits from "system" regulatory affairs costs in proportion to the costs being allocated to Texas. Project F3PCSYSRAS costs are allocated to the subsidiaries based on electric customer counts, and OPC states that it is questionable whether Entergy's positions on "emerging" state or national regulatory issues or "system-wide regulatory strategies" are conveying any benefits to its electric customers beyond those already captured in the Texas-specific regulatory affairs project codes.7 46 In fact, according to OPC, the Company's shareholders are the primary beneficiaries of these system-wide regulatory strategies.747 The federal regulatory affairs costs captured under Project F3PCSYSRAF are allocated to the regulated subsidiaries based on each company's load responsibility ratio; this ratio assumes that every FERC docket and/or FERC issue is related to ETI' s peak demand. According to OPC, this is not reality, nor is it consistent with FERC's primary responsibility to ensure that electric wholesale buyers and sellers are provided open access transmission across utility systems. ETI witness May offered the following as rebuttal of Dr. Szerszen's contentions regarding these two project codes: The affiliate charges to Project Codes F3PCSYSRAS and F3PCSYSRAF are directly associated with the issues and matters within the federal jurisdiction of the Federal Energy Regulatory Commission ("FERC") including but not limited to the Open Access Transmission Tariff ("OATT") as well as any other federal statutes, rules and 744 OPC Ex. 3 (Szerszen Workpapers) at 365. 745 OPC Ex. l (Szerszen Direct) at 46-47; OPC Ex. 3 (Szerszen Workpapers) at 367. 746 OPC Ex. 3 (Szerszen Workpapers) at 368-371. 747 OPC Ex. 1 (Szerszen Direct) at 47. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE214 PUC DOCKET NO. 39896 regulations. These are the result of issues and matters raised concerning the OATT, operations of the transmission system, requests for transmission service and interpretation of applicable provisions under the jurisdiction of FERC. They are costs incurred on an Entergy System-wide basis that cannot be directly assigned to any one Operating Company, such as ETI.748 He then went on to state that the affiliate Test Year issues and costs related to these project codes are 749 reflective of typical issues and costs that the Company experiences on an ongoing basis. With respect to the benefits derived by Texas ratepayers as a result of activities conducted under these project codes, Mr. May stated that: the benefit to ETI involves a multitude of issues that are directly related to the jurisdiction of the FERC, including but not limited to any revisions to Service Schedules under the System Agreement that applies to all operating companies including ETI, power purchase agreements for cost-based, short-term power sales, and compliance with FERC by each Operating Company to the market-based rate tariff and cost-based rate tariff. The Entergy Operating Companies' market-based rate tariff and cost-based rate tariff are joint tariffs containing terms and conditions of service. 750 Mr. May also explained why the billing methods applied to these two project codes are appropriate. The cost drivers for Project F3PCSYSRAF are labor, employee expenses, consultant expenses, and other general operating expenses incurred for the benefit of the Entergy Operating Companies and their regulated customers. Therefore, a billing method based on load responsibility "LOADOPCO" is appropriate for this type of project code. Project F3PCSYSRAS captures costs associated with general regulatory support work that is applicable across all of the jurisdictions. The primary activities associated in this project code include but are not limited to: special project work associated with system-wide regulatory matters, analysis of emerging state or national regulatory and accounting issues affecting the Entergy System, and internal process improvement work. What drives the cost of this project code is the average number of both electric and gas customers served- 748 ETI Ex. 57 (May Rebuttal) at 25. 749 ETI Ex. 57 (May Rebuttal) at 25. 750 ETI Ex. 57 (May Rebuttal) at 27-28; see also, Tr. at 370-371. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE215 PUC DOCKET NO. 39896 CUSTEGOP because all such customers benefit from these services provided by ESI to ETI.751 In short, according to ETI, the activities undertaken under both of these project codes benefit Texas ratepayers, and they are properly allocated to the regulated operating companies using the billing methods employed. The AU s believe that resolution of this question is a close call. Although ETI provided an adequate explanation of the reasons underlying the allocation of costs to Texas ratepayers and the appropriateness of the allocation methodologies used, the one troubling aspect, as noted by OPC, was that Mr. May's testimony regarding Projects F3PCSYSRAF and FP3PCSYSRAS contradicted the fact that ESI has a specific project dedicated to open access transmission issues entitled "FERC- Open Access Transmission" (Project F3PCE01601). 752 As OPC notes, if Mr. May was correct that OATT issues have been included in Projects F3PCSYSRAF and FP3PCSYSRAS the project pages should arguably be more specific about the purpose of the expenditure. Nevertheless, the AU s find ETI' s testimony credible and recommend that the costs of Projects F3PCSYSRAF and FP3PCSYSRAS not be disregarded. H. Financial Services Class Dr. Szerszen recommended disallowances in nine project codes that are primarily captured within ETI's Financial Services Class of affiliate costs: (1) F3PCF05700 (Corporate Planning & Analysis) for a disallowance of $4,254; (2) F3PCF21600 (Corp Rptg Analysis & Policy) for a disallowance of $320,157; (3) F3PCFF1000 (Financial Forecasting) for a disallowance of $96,734; (4) F3PPADSENT (Analytic/Decision Support-Entergy) for a disallowance of $93,544; (5) F3PPSPSENT (Strategic Planning Svcs-Entergy) for a disallowance of $45,265; (6) F3PCR73345 (Quick Payment Center, Adm) for a disallowance of $14,484; (7) F3PCF20990 751 ETI Ex. 57 (May Rebuttal) at 28-29. 752 OPC Ex. l l; also found in OPC Exhibit No. 3 (Szerszen Workpapers )at 363-364. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE216 PUC DOCKET NO. 39896 (Operations Exec VP & CFO) for a disallowance of $146,267; (8) F3PCFF1001 (OCE Support) for a disallowance of $1,923; and (9) F3PCF23936 (Manage Cash) for a disallowance of $15,677.753 1. Projects F3PCF05700 (Corporate Planning & Analysis), F3PCF21600 (Corp Rptg Analysis & Policy), F3PCFF1000 (Financial Forecasting), F3PPADSENT (Analytic/Decision Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs- Entergy) Dr. Szerszen proposed to disallow all costs related to these five project codes, which she collectively describes as addressing Corporate Planning, Reporting, and Forecasting issues because she contends that an assets-based allocator should not be used to allocate these costs and, regardless of the allocator used, these types of services do not benefit Texas ratepayers because ESI has, in other instances, directly billed corporate-level services to ETI. ETI witness Tumminello responded, stating that Dr. Szerszen failed to consider the Entergy organization as a family of companies and ETI's place in that family. The services provided under these project codes are not only relevant to ETI as part of the Entergy family, but are reasonable and necessary. ESI' s corporate oversight services are provided to both individual companies and groups of companies within the Entergy Companies' corporate structure. As a member of the corporate group, ETI receives the benefit of corporate-level planning, reporting, and forecasting activities provided by ESL Ms. Tumminello contested that the use of an asset-based allocator is appropriate because this is an example of the stewardship of the company-wide assets and such an allocator is, therefore, appropriate. 754 The AU s agree. The AUs find that ETI's proposed allocator is appropriate and that the costs benefit Texas ratepayers. Accordingly, the AUs recommend the Commission approve the costs proposed by ETI. 753 OPC Ex. I (Szerszen Direct) at 56, 60-62, and 74, and Schedules CAS-9, CAS-10, and CAS-15. 754 ETI Ex. 69 (Tumminello Rebuttal) at 10-11. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE217 PUC DOCKET NO. 39896 2. Projects F3PCF20990 (Operations Exec VP & CFO) and F3PCFF1001 (OCE Support) Dr. Szerszen recommended disallowance of all costs captured by these project codes because, in her opinion: (1) there are "no perceivable benefits to ETI's ratepayers"; (2) they should be paid for by the parent entity (presumably meaning Entergy's shareholders); and (3) an asset.s-based allocator is not appropriate. 755 As to Dr. Szerszen' s assertion that Texas ratepayers do not benefit from the costs captured by these project codes, ETI witness Domino, President of Entergy, provided anecdotal evidence that that Entergy was vital to ETI' s restoration efforts on two fronts. First, the parent provided cash to ETI for its hurricane restoration efforts; second, ETI was not required to pay dividends to the parent while it was strapped for funds due to hurricane restoration efforts. 756 With respect to the argument that an asset-based allocator is not appropriate, Ms. Tumminello testified that the functions covered by this project code relate to the oversight of all system operations and the stewardship of corporate assets and that because ETI is part of a corporate group, the allocated charges associated with these services are relevant to ETI as part of that group. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the cause of the costs incurred, in that services provided relate to the stewardship of all the corporation's assets. 757 Dr. Szerszen took too narrow a view and, without justification, argued that these costs provide no benefit to Texas ratepayers. There are innumerable benefits provided by the corporate structure adopted; those mentioned by Mr. Domino are just a few. Ms. Tumminello's testimony explained why an asset-based allocator is appropriate. Accordingly, the AUs recommend the Commission approve the inclusion of these costs as requested by ETI. 755 OPC Ex. 1 (Szerszen Direct) at 56-57. 756 Tr. at 141. 757 ETI Ex. 69 (Tumminello Rebuttal) at 9-11. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE218 PUC DOCKET NO. 39896 3. Project F3PCR73345 (Quick Payment Center, Adm) Dr. Szerszen recommended that these costs be reallocated using the CUSTCALL billing method. Given ESI's demonstrated tracking capabilities, Dr. Szerszen reallocated the costs of this project using a 10.8 percent customer call allocator, which is on the low end of the 10.70 percent-11.04 percent Test-Year CUSTCALL allocators. 758 As a result of Dr. Szerszen's reallocation, $14,484 associated with this project should, according to Dr. Szerszen, be disallowed.759 ETI witness Stokes responded, stating that Dr. Szerszen's proposed reallocation is arbitrary and fails to consider the cost causation associated with the actual project code at issue. These costs are not driven by a specific proportion of calls from each Operating Company (that is, by the CUSTCALL allocator). The costs captured by Project F3PCR73345 reflect the costs of overseeing the Quick Payment Center vendors in each of the Entergy Operating Companies, regardless of the number of calls by customers to the Company. 760 The AI.Js are persuaded that the allocation methodology chosen by ETI is the superior method and that the CUSTCALL allocator would not be appropriate given the cost causation associated with the project. Accordingly, the AI.Js recommend the Commission approve the costs proposed by ETI. 4. Project F3PCF23936 (Manage Cash) Dr. Szerszen recommended disallowance of $15,677 from Project F3PCF23936 (Manage Cash), arguing that this project: (1) is duplicative of ETl-specific financing and cash management 758 OPC Exhibit No. 27 (ETI' s Ex. SBT-15, Attachment 6) at 2; Tr. at 838-839. 759 OPC Exhibit No. 1 (Szerszen Direct) at 77 and 118. 760 ETI Ex. 66 (Stokes Rebuttal) at 11. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE219 PUC DOCKET NO. 39896 activates; (2) the allocator is wrong; and (3) Entergy, not ETI ratepayers, should pay for this activity. 761 ETI witness McNeal testified that the services are not duplicative of the cash management services performed by the Cash Management department in the Treasury Class. The services provided under Project F3PCF23936 are associated with daily cash management responsibilities, such as loading bank balances, setting daily cash position for all the Entergy Companies, transmitting wire/ACH files to Entergy Company banks for vendor payments, and maintaining proper cash controls over these cash functions. These services are necessary for the daily operation of all the Entergy Companies, including ETI, and are thus not directly associated with any one specific legal entity. The costs are driven by the time spent on the daily cash management activities, which is directly related to the number of bank accounts that the Entergy Companies have open. Since the services provided under this project code cannot be identified to a particular Entergy Company, the billing method based on the number of open bank accounts is the best allocation. Billing method BNKACCTA does that and, according to Mr. McNeal, is therefore appropriate for allocating costs for this project code. 762 The evidence demonstrates that the activities captured by this project code are not directly associated with any one specific entity; rather, they benefit all the entities under the Entergy umbrella. It also appears that a billing method based on the number of open bank accounts is the appropriate allocation methodology. Accordingly, the ALls recommend the Commission approve inclusion of costs as requested by ETI. I. Human Resources Class Dr. Szerszen recommended dis allowances for three project codes that are primarily within the Human Resources Class of affiliate costs: (1) F3PCHRCCSM (HR Competitive Compensation) for a disallowance of $20,146; (2) FSPCZUBENQ (Non-Qualified Post-Retirement) for a disallowance 761 OPC Ex. l (Szerszen Direct) at 74 and Schedule CAS-15. 762 ETI Ex. 61 (McNeal Rebuttal) at 4, 6; Tr. at 546-547. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE220 PUC DOCKET NO. 39896 of $115,078; and (3) F5PPZNQBDU (Non-Qual Pension/Benf-Dom Utl) for a disallowance of $241,073. 763 1. Project F3PCHRCCSM (HR Competitive Compensation) Dr. Szerszen testified that an asset-based allocator is not appropriate for a project, such as Project F3PCHRCCSM, that captures overall executive management-related costs.764 ETI contends that the functions covered by this project code relate to the oversight of all system operations and the stewardship of corporate assets and that because ETI is part of a corporate group, the allocated charges associated with these services are relevant to ETI as part of that group of companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the cause of the costs incurred, in that services provided relate to the stewardship of all the corporation's assets. 765 A corporation cannot function without executives, who are charged with the responsibility of overseeing, among other things, the assets of the corporation. This is an important function that Dr. Szerszen did not acknowledge in her testimony. The utility and executive management class costs that she challenged are reasonable and necessary costs that are allocated to ETI based on a logical allocator - the assets the executives are charged with overseeing. The AU s recommend that OPC' s challenge be rejected. 2. Projects FSPCZUBENQ (Non-Qualified Post-Retirement) and FSPPZNQBDU (Non-Qual Pension/Benf-Dom Utl) With respect to Projects F5PCZUBENQ and F5PPZNQBDU, Dr. Szerszen testified that: (1) there is no evidence that Texas ratepayers benefit from the pension-related benefits in these 763 OPC Ex. I (Szerszen Direct) at 56, 68. 764 OPC Ex. I (Szerszen Direct) at 56. 765 ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-1 l. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE221 PUC DOCKET NO. 39896 codes; and (2) the LBRBILAL allocator (Labor Billings to All) is not appropriate because the benefits are unrelated to ESI labor costs. 766 Initially, ETI agrees that $112,531 of the costs in total for both of these project codes should be excluded because that amount is attributable to nuclear and non-regulated employees.767 With respect to the remaining costs, ETI disagrees. The AUs, however, have already resolved this issue in their discussions related to Section VII.D.4, above, where they concluded that that the supplemental executive retirement plans are not reasonable and necessary for the provision of electric utility service and are not in the public interest. Accordingly, the Al.Js recommend the Commission accept OPC' s proposed disallowance of $356, 151 (which includes the $112,531 agreed to by ETI). J. Information Technology Class Dr. Szerszen recommended disallowances in two project codes that are primarily within ETI's Information Technology Class: (1) F3PPFXERSP (Evaluated Receipts Settlement) for a disallowance of $10,279; and (2) F3PCFX3555 (BOD/Executive Support) for a disallowance of $3,148. 768 1. F3PPFXERSP (Evaluated Receipts Settlement) Dr. Szerszen testified that Project F3PPFXERSP is not moving forward due to tax and freight implications and, as such, the cost is not recurring. 769 Ms. Tumminello testified in response that the "Evaluated Receipt Settlement" program was originally being capitalized in a capital project. But when it was decided that the program would be cancelled, the capital project was closed and the charges to the project were expensed. Although the costs for this particular project do not recur 766 OPC Ex. l (Szerszen Direct) at 68. 767 ETIInitial Brief at 179. 768 OPC Ex. l (Szerszen Direct) at 56, 71. 769 OPC Ex. 1 (Szerszen Direct) at 71. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE222 PUC DOCKET NO. 39896 every year, they are part of normal utility operations, and this type of project does recur as necessary.770 Although the AU s understand the concept of normally recurring cost types, they do not believe that the costs captured by this project code fall within that category. Those costs related to a project that was cancelled and sufficient explanation of how similar projects in the future might occur was not provided. Accordingly, the ALls recommend the Commission reject inclusion, as proposed by OPC. 2. Project F3PCFX3555 (BOD/Executive Support) Dr. Szerszen argued that Project F3PCFX3555 is an executive-related project that does not provide perceivable benefits to ETI ratepayers, the Entergy shareholders should bear this cost, and an assets-based allocator is not appropriate. 771 ETI argues that the functions covered by this project code relate to the oversight of all system operations and the stewardship of corporate assets and that because ETI is part of a corporate group, the allocated charges associated with these services are relevant to ETI as part of that group of companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the cause of the costs incurred, in that services provided relate to the stewardship of all the corporation's assets. 772 A corporation cannot function without executives who are charged with the responsibility of overseeing, among other things, the assets of the corporation. This is an important function that Dr. Szerszen did not acknowledge in her arguments. The utility and executive management class costs that she challenged are reasonable and necessary costs that are allocated to ETI based on a logical allocator- the assets the executives are charged with overseeing. The AU s recommend that OPC's challenge be rejected. 770 ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4. 771 OPC Ex. 1 (Szerszen Direct) at 56. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE223 PUC DOCKET NO. 39896 K. Internal and External Communications Class Dr. Szerszen recommended disallowances in four project codes that are primarily within ETI' s Internal and External Communications Class: ( 1) F3PCR40118 (Utility Communications for a $6 disallowance; (2) FSPCZPDEPT (Supervision and Support- Public) for a $138 disallowance; (3) FSPPICCOOO (Integrated Customer Communications) for a $199 disallowance; and (4) FSPPICCEMP (ICC - Employee Education Initiative) for a $3 disallowance.773 ETI witness Tumminello responded to Dr. Szerszen's claim that the costs captured by these project codes are corporate image costs by stating that the costs are for advertising activities that are of a good will or institutional nature, which is primarily designed to improve the image of the utility or the industry, including advertisement which inform the public concerning matters affecting the Company's operations, such as, the costs of providing service, the Company's efforts to improve the quality of service, the Company's efforts to improve and protect the environment. According to FERC, such costs are properly includable inFERCAccount 930.1 and are recoverable. According to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the recoverability of these costs. 774 OPC provided little support for its claim that costs covered by these project codes should not be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers should not be charged with such costs. ETI did little better, but it did provide the testimony of Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and are, therefore, recoverable. In the end, the AUs must go with the weight of the evidence, which is in ETI's favor. The AUs recommend the Commission reject OPC's contention that costs covered by these project codes are not recoverable. 772 ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11. 773 OPC Ex. l (Szerszen Direct) at 66. 714 ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE224 PUC DOCKET NO. 39896 L. Legal Services Class Dr. Szerszen recommended disallowances in 13 project codes that are primarily within the Legal Services Class: (1) F3PPCASHCT (Contractual Altemative/Cashpo) for a disallowance of $2,553; (2) F3PCF99180 (CORP. COMPLIANCE TRACKING SYS) for a disallowance of $9; (3) F3PPINVDOJ (DOJ Anti Trust Investigation) for a disallowance of $1,039,664; 775 (4) F3PCE01601 (Ferc - Open Access Transmission) for a disallowance of $84,183; (5) F3PCERAKTL (RAKTL Patent Matter) for a disallowance of $75; (6) F3PPEASTIN (Willard Eastin et al) for a disallowance of $19,714; (7) F3PPTCGS11 (TX Docket Competitive Generation) for a disallowance of $310,746; (8) F5PCE13759 (Jenkins Class Action Suit) for a disallowance of $205,l 07; (9) F5PCZLDEPT (Supervision & Support- Legal) for a disallowance of $225,794; (10) F3PCCDVDAT (CorporateDevelopmentDataRoom)foradisallowanceof $6,147; (11) F3PCSYSAGR (SystemAgreement-200l)for a disallowanceof$880,841; (12) F3PPWET302 (SPO 2008 Winter Western Region) for a disallowance of $13,919; and (13) F3PPWET308 (SPO Calpine PPA/Project Houston) for a disallowance of $435,963. 1. Project F3PPCASHCT (Contractual Altemative/Cashpo) With respect to Project F3PPCASHCT ($2,553 disallowance), ETI agrees that these costs are non-recurring and should be disallowed. Accordingly, the AUs recommend the Commission exclude those costs. 2. Project FSPCZLDEPT (Supervision & Support - Legal) As to Project F5PCZLDEPT ($225,794), OPC, through its Second Errata, removed that proposed disallowance, and it is no longer contested by Dr. Szerszen. Accordingly, the AUs recommend the Commission approve inclusion of those costs. 775 Dr. Szerszen also proposed disallowance of $765 in charges for related Project Code F3PPTDHY 19 (Dept. of Justice Investigation), which is actually primarily attributable to the Transmission Operations Class, rather than the Legal Services Class. Because the issues are intertwined, that project will be discussed here, rather than in the Transmission Operations Class. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE225 PUC DOCKET NO. 39896 3. Project F3PCF99180 (Corp. Compliance Tracking Sys) F3PCF99180 (Corp. Compliance Tracking Sys) is one of the project codes that Dr. Szerszen claimed should be disallowed because ETI is a monopoly and Texas ratepayers should not have to pay for corporate image costs. 776 ETI witness Tumminello testified that these costs are for advertising activities that are of a good will or institutional nature, which is primarily designed to improve the image of the utility or the industry, including advertisement which inform the public concerning matters affecting the Company's operations, such as, the costs of providing service, the Company's efforts to improve the quality of service, the Company's efforts to improve and protect the environment. According to FERC, such costs are properly includable in FERC Account 930.1 and are recoverable. According to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the recoverability of these costs. 777 OPC provided little support for its claim that costs covered by these project codes should not be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers should not be charged with such costs. ETI did little better, but it did provide the testimony of Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and are, therefore, recoverable. The weight of the evidence is in ETI' s favor. The ALls recommend the Commission reject OPC' s contention that costs covered by these project codes are not recoverable. 4. Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and F3PPTDHY19 (Dept. of Justice Investigation) Entergy is currently under investigation by the Department of Justice (DOJ) for certain business practices of the Operating Companies, including the procurement of generating assets and power, dispatch of generation within the Entergy system, and transmission capacity expansion. This is a civil investigation under Section 2 of the Sherman Act and Section 7 of the Clayton Act. The 776 OPC Ex. I (Szerszen Direct) at 66. 777 ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE226 PUC DOCKET NO. 39896 investigation has been ongoing since 2010, and Entergy does not know when the investigation will conclude. 778 Dr. Szerszen testified that there are two reasons why ratepayers should not pay for the DOJ expenses. First, ETI does not have the ability to make its own power procurement, generation dispatch, or transmission capacity decisions. These decisions are made by ESI and Entergy' s corporate management, which has traditionally planned and managed the electric operating companies' generation and transmission functions on a system-wide basis. Second, ETI is not responsible for the development and administration of the system agreement, and should not be held responsible for these antitrust investigation expenses. Furthermore, according to Dr. Szerszen, if the DOJ finds that Entergy has acted illegally, it is even more inappropriate to charge ETI ratepayers for corporate-level illegal actions. These expenses should be borne by Entergy's corporate parent and/or the corporation's shareholders, and not the ratepayers. 779 ETI contends that Dr. Szerszen fundamentally misunderstands the nature of the System Agreement and the benefits that ETI derives from that agreement. All of the Entergy Operating Companies voluntarily entered into the System Agreement so that the Entergy system can be planned and operated on a total system basis, in order to maximize economic benefit and reliability of service. All of the Operating Companies benefit from integrated planning and operations in this manner. This does not mean that ETI has no decision-making role in these activities. ETI notes that under Section 5.01 of the System Agreement, the agreement is administered through an Operating Committee, which includes an ETI representative, as well as representatives of the other Operating Companies and Entergy. ETI' s representative is one of the voting members of the Committee, and all decisions of the Operating Committee must be approved by a majority vote. As a voting member of the Operating Committee, ETI is responsible for administering the System Agreement and does participate in decision-making on generation and transmission matters. 780 778 OPC Ex. 1 (Szerszen Direct) at 51-52. 779 Id. at 52. 780 ETI Ex. 65 (Sloan Rebuttal) at 8. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE227 PUC DOCKET NO. 39896 ETI acknowledges that ESI is tasked with providing services and making decisions related to generation dispatch, power procurement, and transmission operations on behalf of the Entergy Operating Companies and at the direction of the Operating Committee, but these activities are for the benefit of the Operating Companies and their ratepayers. ETI receives the benefits of these services and integrated planning and operations under the System Agreement and, according to ETI, should also be responsible for its portion of costs related to those services and operations. 781 As to Dr. Szerszen' s contention that the costs should be disallowed because DOJ might find that Entergy acted illegally, ETI notes that the DOJ is not an adjudicatory body or regulatory agency and, thus, it does not make "findings of fact." If DOJ believes the civil antitrust laws have been violated, it can file a complaint in federal district court. To date, no complaint has been filed. ETI points out that ESI routinely incurs legal costs in responding to regulatory audits and investigations on behalf of ETI and the other Operating Companies in the same manner in which other operating costs are incurred. ESI is authorized to retain legal counsel on behalf of, and for the benefit of, ETI and the other Entergy Operating Companies. ESI is authorized to allocate the respective costs to the Operating Companies under a service agreement with the Entergy Operating Companies designated as Rate Schedule FERC No. 435. This service agreement is on file with, and was approved by, FERC under FER C Docket No. ER07-38-000. 782 Thus, according to ETI, it is appropriate that ETI is allocated its share of the costs of legal services related to the DOJ investigation. 783 The DOJ antitrust investigation is a massive undertaking. Unfortunately, it is a part of the ordinary course of modem business life. OPC's arguments that ESI is solely responsible for decision-making under the System Agreement miss the mark, as pointed out by ETI. It is clear that ETI and the other Operating Companies play an active role in the decision-making. As to OPC's arguments about what would happen if Entergy were found to have violated the antitrust laws, those arguments are little more than speculation. As ETI noted, the DOJ is not an adjudicatory body and its investigation can only result in the filing of a complaint in Federal court (if the DOJ believes that 1s1 Id. 782 Entergy Serv. Inc., 117 FERC 1 6 l ,288 (2006 ). 783 ETI Ex. 65 (Sloan Rebuttal) at 8-9. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE228 PUC DOCKET NO. 39896 such an action is justified). Until that time, it is imperative for the company to fully respond to the DOJ investigation. The Al.Js find that ETI has met its burden of proving that Texas ratepayers should be charged the costs of the DOJ investigation allocated to them by ETI. S. Project F3PCE01601 (Ferc - Open Access Transmission) Project F3PCEO 1601 costs are incurred to manage costs associated with regulatory oversight and coordination of the Entergy System Open Access Transmission Service before FERC. OPC contends that not only are most of the FERC dockets accruing costs under Project F3PPEO 1601 no longer open as of December 31, 2011, 784 most of the closed dockets have absolutely nothing to do with Texas operations.785 Furthermore, according to OPC, ETI witness Sloan agreed that only three of the dockets shown in OPC Exhibit No. 12 were open at the end of the test year, and one of the open dockets involves a transmission service agreement involving the Missouri Joint Municipal Electric Utility Commission and various cities in Missouri and Arkansas.786 ETI responds that the activities in this project relate to oversight and coordination of the OATT proceedings before the FERC. Costs billed to this project code are related to ESI's representation of the Operating Companies, including ETI, before the FERC on OATT issues. Revenues derived from provision of service under the OATT are credited to all of the Operating Companies on a load responsibility ratio basis. ETI' s retail share of these revenues was $168,366 during the test period, demonstrating the benefits derived by Texas ratepayers as a result of the activities undertaken through this project code. 787 Activities relating to a company's OATT are not one-time activities; they will continue from year to year. OPC's contention that because most of the dockets listed as having taken place during the Test Year were completed by the end of the Test Year they should be disregarded is not 784 OPC Ex. 12 (OPC RPI No. 7-3); OPC Ex. 3 (Szerszen Workpapers) at 363. 785 OPC Ex. 12 (OPC RFI No. 7-3); OPC Ex. l (Szerszen Direct) at 54. 786 Tr. at 280. 787 ETI Ex. 65 (Sloan Rebuttal) at 10. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE229 PUC DOCKET NO. 39896 well-founded. It is clear that the activities covered by this project code not only benefit ETI' s Texas ratepayers, but will continue (albeit under new docket numbers) into future years. The AUs recommend that costs under this project code be allowed. 6. Project F3PCERAKTL (RAKTL Patent Matter) The costs under this project code involve the RAKTL patent, which relates to call center operations. RAKTL is a patent infringement claim lodged against several Entergy companies. The alleged patents are for voice prompting technology used in call centers. 788 Dr. Szerszen testified that it is not appropriate to charge ETI for the costs associated with this litigation because ETI did not purchase the call center telephone equipment at issue, and therefore should not be required to pay any legal costs associated with patent infringement investigation or settlement costs. ESI is totally responsible for system-wide technology purchases and operations, and, according to Dr. Szerszen, it is not reasonable to require the operating companies to pay legal costs associated with ESI technology acquisition or technology application errors.789 ETI contends that ESI incurred the legal expenses on this patent matter on behalf of the Entergy Operating Companies, whose residential and small commercial customers call into the call centers to obtain customer service for issues related to connection and disconnection of electric service, billing issues, and other customer transactions. The call centers provide an interface between ETI customers and the Entergy Operating Companies and, as such, are valuable in providing quality service to customers. Consequently, according to ETI, costs related to the call centers, including the costs of defending lawsuits involving technologies used at those call centers, is a reasonable and necessary expense that is appropriately allocated to ETI.790 OPC tends to ignore the purpose and benefits of a centralized service company such as ESL If ETI were to fund stand-alone call centers, it is likely that the costs to Texas ratepayers would be 788 Id. at 4; OPC Ex. 1 (Szerszen Direct) at 49-50. 789 OPC Ex. I (Szerszen Direct) at 50. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE230 PUC DOCKET NO. 39896 higher than those proposed by ETI in this case. Part of the costs that ESI incurs is the cost of patent claims. Those are legitimate costs that should be borne by all who receive service from ESI. Accordingly, the ALls recommend the Commission reject OPC's challenge. 7. Project F3PPEASTIN (Willard Eastin et al.) This project code, which contains costs in the amount of $19,714, collects costs related to an age discrimination law suit filed by Willard Eastin, et al. against Entergy. The defendants to the lawsuit were Entergy, ESI, Entergy Louisiana, fuc. (ELL), and Entergy New Orleans, fuc. (ENOI). The plaintiffs to the lawsuit were employees of ESI, ELL, and ENOI.791 OPC witness Szerszen testified that ETI should not be required to pay any of the costs of this litigation. Although ESI provides services to the Operating Companies, this does not imply that the Operating Companies should be charged costs associated with the service company's employment 792 practice problems or errors according to Dr. Szerszen. ETI argues that costs are driven by ESI having the need for legal services to defend itself. As shown on the Project Code Summary for this project, since all ESI functions are in service to the various affiliates and arise as a consequence of providing such services, it is appropriate to relate these legal costs to the total ESI billings to the affiliates. 793 ETI has provided little in the way of explanation regarding these costs or the litigation that generated them. What is troubling to the AUs is that the only named defendants are Entergy, ESI, ELL, and ENOI; ETI is not included among the named defendants. If this were simply a cost of doing business for ESI, as claimed by ETI, why were ELL and ENOI named? No explanation was offered. It appears to the ALls that although this litigation is related to ESI's operations, it is more 790 ETI Ex. 65 (Sloan Rebuttal) at 4. 791 ETI Ex. 65 (Sloan Rebuttal) at 2; OPC Ex. 1 (Szerszen Direct) at 49-50. 792 OPC Ex. 1 (Szerszen Direct) at 50. 793 ETI Ex. 65 (Sloan Rebuttal) at 2. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE231 PUC DOCKET NO. 39896 immediately related to ELL and ENOI. The AUs do not believe that ETI's Texas ratepayers should be charged for these costs; therefore the AUs recommend that $19,714 not be included. 8. Project F3PPTCGS11 {TX Docket Competitive Generation) The costs billed through this project code all pertain to ETI' s CGS matter currently pending before the Commission in Docket No. 38951. 794 OPC witness Szerszen testified that because no decision has been made yet as to the disposition of the expenses associated with the CGS tariff, ETI should not be expensing the costs associated with that docket. Dr. Szerszen disallowed $310,746 in Test-Year expenses, and recommended that ETI be allowed to defer the expenses until the Commission determines the appropriate regulatory treatment. 795 ETI argues that these costs were incurred during the Test Year in a pending Commission docket, and ETI continues to incur costs related to this matter. As such, according to ETI, these costs are appropriately included in ETI' s cost of service and should neither be disallowed nor deferred.7 96 OPC's arguments with respect to these costs are not well-founded. It appears to be likening these regulatory costs to rate case expense, which would be subject to Commission review and approval in the proceeding to which they relate. But that is not the nature of these expenses. They are simply regulatory expenses incurred in the course of ongoing regulatory proceedings. They are ordinary and necessary expenses, the reasonableness of which OPC did not challenge. Accordingly, the AU s find that it is appropriate for ETI to charge these expenses to its Texas ratepayers. 794 Id. at 5; OPC Ex. 1 (Szerszen Direct) at 50. 795 OPC Ex. l (Szerszen Direct) at 50. 796 ETI Ex. 65 (Sloan Rebuttal) at 5. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE232 PUC DOCKET NO. 39896 9. Project FSPCE13759 (Jenkins Class Action Suit) The project code relates to a class action lawsuit filed in Texas District Court in 2003 on behalf of all Texas retail customers served by ETI's predecessor-in-interest, EGSI (Jenkins Class Action). The Jenkins Class Action plaintiffs allege that they have been damaged due to manipulation of the dispatch and pricing of the Entergy system's generating units and electricity purchases. As a result of this alleged manipulation, they contend that ETI's Texas retail customers were charged more than they should have been for purchased power.797 Dr. Szerszen asserted there are three reasons why these legal expenses should not be borne by ETI: • ESI charges 100 percent of the legal expenses to ETI, even though ETI is only one of several defendants; • ETI claims that it is defending practices relating to system operations, but fails to acknowledge that Entergy' s system operations are comprised of many generation and transmission components other than those of ETI; and • ETI does not have any authority to administer the System Agreement, that being a function solely within the purview of ESI.798 Dr. Szerszen testified that "[i]t would be more appropriate for the Entergy parent to be charged for these lawsuit expenses, particularly since ETI cannot make unilateral power purchases and power sales decisions."799 ETI responds that the plaintiffs in this lawsuit are challenging the reasonableness of ETI' s Commission-set rates and that the Commission has filed an amicus brief in support of ETI' s position in the case. ETI further argues that retail ratepayers are benefitting from ETI' s pursuit of the litigation because ETI is defending practices that are in place to ensure the lowest reasonable cost consistent with system reliability. Finally, ETI states that the costs are reasonable and necessary 797 OPC Ex. 1 (Szerszen Direct) at 49; ETI Ex. 65 (Sloan Rebuttal) at 2-3. 798 OPC Ex. l (Szerszen Direct) at 49. 799 Id. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE233 PUC DOCKET NO. 39896 expenses because the plaintiffs purport to represent only ETI's ratepayers and seek to recover damages inconsistent with ETI' s filed rates approved by the Commission. 800 The ALls understand Dr. Szerszen's concerns that there are multiple defendants involved in this litigation, there are many aspects to Entergy' s system operations, and ETI does not have power to unilaterally make decisions under the System Agreement. The crucial point, however, is that these are Texas ratepayers pursuing a challenge to ETI's Texas rates. The matter centers around Texas, and the costs of the litigation should be borne by Texas ratepayers. 10. Project F3PCSYSAGR (System Agreement-2001) OPC witness Szerszen disallowed $880,841 in legal expenses regarding the 2001 complaint filed by the Louisiana Public Service Commission and the City of New Orleans seeking revisions to the Entergy System Agreement. 801 OPC states that it generally agrees with ETI witness Sloan that the complaint challenges the equalization of costs between all Entergy Operating Company jurisdictions. 802 However, OPC does not agree that the inquiry "will" affect all Entergy jurisdictions. Texas has benefitted from the complaint primarily through the past receipt of equalization payments pursuant to FERC's decision in this complaint matter. However, Entergy's SEC FormlO-K shows that for 2012 and 2013, ETI will receive no equalization payments, and further shows that ETI received no rough production cost equalization payments in 2010. 803 Thus, according to OPC, the legal expenses sought to be recovered under Project F3PCSYSAGR are non-recurring for ETI and therefore not representative of future costs and should be removed from ETI' s cost of service. 804 ETI established that this litigation involved the System Agreement, which governs the equalization of costs between all of the Entergy Operating Company jurisdictions, it provides benefits to ETI's Texas ratepayers as well as those of the other Entergy Operating Companies. 800 ETI Ex. 65 (Sloan Rebuttal) at 3. 801 OPC Ex. 1 (Szerszen Direct) at 53. 802 ETI Ex. 65 (Sloan Rebuttal) at 9. 803 ETI Ex. 98 (Entergy's SEC Fonn 10-K) at 79-80. 804 OPC Ex. 1 (Szerszen Direct) at 52-53. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE234 PUC DOCKET NO. 39896 OPC' s argument that ETI did not receive equalization payments in 2010 and is non-recurring for ETI does not overcome the benefits received by ETI's Texas ratepayers. The ALls recommend that OPC's disallowance be denied. 11. Project F3PCCDVDAT (Corporate Development Data Room) ETI requests the recovery of $6, 147 in ESI allocated costs for the corporate development data room. The stated purpose of the data room is for due diligence reviews associated with Entergy merger, acquisition, or diversification activities. The expenses associated with the corporate development data room are for the gathering, collating, indexing, manning, and storage of data during the due diligence reviews. 805 OPC contends that the costs incurred for the corporation's analysis of merger, acquisition, and diversification opportunities should not be charged to ETI's ratepayers. Entergy has not acquired any utilities or utility operations that might produce system-wide benefits to utility customers. 806 The $6, 147 of expenses for the corporate development room are not reasonable and necessary expenses that ratepayers should shoulder and therefore, according to OPC, recovery of these expenses should be disallowed. ETI responds that these costs are driven by each company's need for corporate services and the costs, therefore, are appropriately allocated based on the level of service provided by ESI, which is a reasonable proxy of each company's need for corporate services. 807 Further, just because Entergy has not acquired any utility or utility operations in the recent past does not mean that these are not reasonable and necessary costs. Entergy points out that as Dr. Szerszen noted in her description of this project, it is not only for the acquisition of other operating units, but also used to analyze diversification activities, which is a legitimate and reasonable undertaking by an integrated utility and its parent company. 805 OPC Ex. 3 (Szerszen Workpapers) at 394. 806 OPC Ex. 1 (Szerszen Direct) at 45-46. 807 ETI Ex. 69 (Tumminello Rebuttal) Ex. SBT-R-2 at 1. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE235 PUC DOCKET NO. 39896 The AU s believe that there are legitimate costs that may not on their face appear to be properly allocable to entities such as ETI, but on closer examination they merit such an allocation. These fall into that class. As Ms. Tumminello testified, the Corporate Development Data Room includes costs not only related to mergers and acquisitions, but also diversification activities that could benefit ETI ratepayers. Accordingly, they are properly allocated to ETI ratepayers. 12. Project F3PPWET302 (SPO 2008 Winter Western Region) Dr. Szerszen argued that Project F3PPWET302 costs should be disregarded because they were incurred during the 2008-2009 period, which is outside of the Test Year, and they are nonrecurring. 808 ETI witness Cicio explained that although this project was initiated prior to the Test Year, the costs that the Company seeks to recover through this project code were expenses incurred during the Test Year. These costs included development activities, requests for proposal issuance, bidders' conferences, written and posted questions and answers from market participants and other interested parties, submission of proposals, screening of proposals, proposal evaluation, follow-up questions and clarifications, recommendations and awards, contract negotiations, Independent Monitor reports, and regulatory approvals, if necessary. He stated that these types of costs routinely encompass a multi-year time frame, and the costs required to perform those activities, although associated with a project that may have been initiated several years previously, are properly incurred over the life span of the project. He also stated that they are recurring because they reflect the kinds and levels of charges that would be expected to be incurred on an ongoing basis in association with request for proposals managed by ESI on behalf of the Entergy Operating Companies, and the Company has been involved in these types of solicitations since 2002. 809 The AU s find that the costs captured by Project F3PPWET302 were incurred during the Test Year and represent the kinds and levels of costs routinely incurred on a recurring basis. Accordingly, the AUs recommend the Commission approve their inclusion as requested by ETI. 808 OPC Ex. 1 (Szerzen Direct) at 65. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE236 PUC DOCKET NO. 39896 13. Project F3PPWET308 (SPO Calpine PPA/Project Houston) With respect to Project F3PPWET308, which deals with the Calpine-Carville purchased power agreement, Dr. Szerszen testified that the costs were either non-recurring, or rate case expenses, or expenses that should have been charged to Louisiana ratepayers. 810 ETI witness Cicio explained that these are recurring costs because they reflect the kinds and levels of charges that the Company expects to incur on an ongoing basis in association with RFPs managed by ESI on behalf of the Entergy Operating Companies; they were not incurred as part of some rate case preparation and, therefore, are not a rate case expense that is otherwise sought for recovery by ETI; and the costs in the matter are costs that were billed only to Texas and should not have been billed to Louisiana because there is a separate project code that captures the Louisiana costs that are billed to Louisiana. 811 The AU s find that these costs, like those captured by Project F3PPWET302, are recurring in that they represent the kinds and levels of costs routinely incurred on a year-in and year-out basis. Further, the AU s find that the costs should not have been charged to Louisiana and that there existed a separate project code to capture costs attributable to Louisiana. Accordingly, the AU s recommend the Commission approve the inclusion of these costs as requested by ETI. M. Other Expenses Class Dr. Szerszen recommended disallowances in 11 project codes that are primarily within the Other Expenses Class of affiliate costs: (1) F3PCSPETEI (Entergy-Tulane Energy Institute) for a disallowance of $14,288; (2) F3PCC08500 (Executive VP, Operations) for a disallowance of $4, 117; (3) F3PPBFMESI (ESI Function Migration Relocation) for a disallowance of $4,187; (4) F3PPBFRESI (ESI Business Function Relocation) for a disallowance of $11,444; (5) F3PPDRPESI (ESI Disaster Recovery Plan Charge) for a disallowance of $761; 809 ETI Ex. 45 (Cicio Rebuttal) at 13-14. 810 OPC Ex. I (Szerszen Direct) at 65-66. 811 ETI Ex. 45 (Cicio Rebuttal) at 14-17. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE237 PUC DOCKET NO. 39896 (6) F5PPBFMREL (Business Function Migration Employee) for a disallowance of $33,624; (7) F5PPBFRREL (Business Function Relocation) for a disallowance of $15,624; (8) F5PPBFRSEV (Business Function Relocation Severance) for a disallowance of $3,066; (9) F5PPDRPREL (Disaster Recovery Plan Relocation) for a disallowance of $31,006; (10) F5PPETXRFI (2009 Texas Ike Recovery Filing) for a disallowance of $441; and ( 11) F5PPKATRPT (Storm Cost Processing & Review) for a disallowance of $929. 812 1. Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and F5PPKATRPT (Storm Cost Processing & Review) ETI agrees with Dr. Szerszen that the $14,288 amount she proposed to disallow for Project F3PCSPETEI (Entergy-Tulane Energy Institute) can be treated as a donation, and so should be removed from ETI' s cost of service. ETI also agrees with Dr. Szerszen to remove the $929 billed to ETI under Project F5PPKATRPT (Storm Cost Processing & Review). The charges for the remaining nine project codes, however, are contested. 2. Project F3PCC08500 (Executive VP, Operations) As to Project F3PCC08500 (Executive VP Operations), Dr. Szerszen testified that an asset-based allocator is not appropriate for these types of executive management costs, and there is "no perceivable benefit" to ETI ratepayers for these types of allocated costs. 813 Ms. Tumminello disagreed, stating that asset-based allocation methods are selected for projects where the costs are driven by the oversight and stewardship of corporate assets of the Entergy Companies including, but not limited to, services provided by financial management and certain finance functions, among others. Each Entergy affiliate with assets on Entergy' s consolidated balance sheet will be billed their proportionate share of the costs. The use of the Total Assets 812 OPC Ex. 1 (Szerszen Direct) at 56, 67, and 72. 813 Id. at 56-57. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE238 PUC DOCKET NO. 39896 allocation method is, in fact, an appropriate method to allocate corporate-level corporate governance type services. 814 The A.Us find credible ETI's assertion that the costs captured by this project code are for oversight and stewardship of the corporate assets of Entergy and, therefore, an asset-based allocator is appropriate. Accordingly, the A.Us recommend the Commission reject OPC's challenge to the inclusion of these costs. 3. Projects F3PPBFMESI (ESI Function Migration Relocation), F3PPBFRESI (ESI Business Function Relocation), F3PPDRPESI (ESI Disaster Recovery Plan Charge), FSPPBFMREL (Business Function Migration Employee), FSPPBFRREL (Business Function Relocation), FSPPBFRSEV (Business Function Relocation Severance), FSPPDRPREL (Disaster Recovery Plan Relocation), and FSPPETXRFI (2009 Texas Ike Recovery Filing) The remaining eight of the project codes attributable to the Other Expenses Class all deal with system restoration and business continuity resulting from Hurricane Katrina, with one applying to Hurricane Ike. Dr. Szerszen testified that these costs should be disallowed because they should not be considered to be system restoration costs or, if they are, citing to PURA§ 36.405, ETI should have requested recovery of these costs in its first base rate following Hurricane Katrina (Docket No. 34800). She also testified that ETI has not shown that Texas ratepayers benefited from these costs. 815 Ms. Tumminello testified that because of the magnitude of Hurricane Katrina, these expenses were necessary so that activities in connection with the restoration of service and infrastructure associated with electric power outages affecting customers could continue. These expenses relate to critical functions needed to support storm restoration, such as business function relocation, and provided a direct benefit to ratepayers. Ms. Tumminello stated that the costs in seven of these project codes (F3PPBFMESI, F3PPBFRESI, F3PPDRPESI, F5PPBFMREL, F5PPBFRREL, F5PPBFRSEV, and F5PPDRPREL) are being amortized over five years. Though these particular 814 ETI Ex. 69 (Tumminello Rebuttal) at 9-10. 815 OPC Ex. I (Szertrszen Direct) at 72, Schedule CAS-14. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE239 PUC DOCKET NO. 39896 costs do not recur every year, they are a part of ETI' s normal utility operations given the service area served by ETI, and do recur as necessary. 816 As to Dr. Szerszen's legal conclusion that ETI is no longer authorized to recover Hurricane Katrina costs, ETI argues that PURA § 36.405 does not restrict or even apply to ETI' s recovery of such costs. That section deals with securitization of system restoration costs, but ETI did not seek to securitize any Hurricane Katrina costs. Even so, argues ETI, if that section did apply, it does not restrict system restoration cost recovery solely to Docket No. 34800; that is, the "next base rate proceeding" following the hurricane. Instead, the final clause in PURA§ 36.405(a) states in full that the Company is entitled to recover such costs "in its next base rate proceeding or through any other proceeding authorized by Subchapter C or D." The same point applies to the Hurricane Ike costs; while ETI did securitize the Hurricane Ike costs that it had incurred up to the date subject to that securitization, it continued to incur costs in this test year for that storm restoration (in this case, $441 billed to the Ike-related project code). The costs in these projects were incurred during the test year for this docket and could not have been recovered in an earlier docket. Moreover, ETI' s filing in this docket was filed in accordance with PURA Subchapter C as a rate change proposed by a utility. As such, ETI contends that it is entitled to recover these costs. 817 To the AU s, the most important part of the argument is that ETI did not seek to avail itself of PURA § 36.405 with respect to Hurricane Katrina costs. It is difficult to understand how that section, which deals with securitization of hurricane costs, could block recovery when ETI did not seek to securitize those costs. Similarly, with respect to Hurricane Ike costs, the $441 challenged by Dr. Szerszen was not incurred until the Test Year and could not have been securitized. Ms. Tumminello provided testimony that the costs were reasonable and necessary, representing a part of ETI' s normal utility operations. Accordingly, the AU s recommend the Commission approve inclusion of the costs. 816 ETI Ex. 69 (Tumminello Rebuttal) atl6. 817 ETI Initial Brief at 188-189. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE 240 PUC DOCKET NO. 39896 N. Regulatory Services Class Dr. Szerszen challenged one project code that is primarily within the Regulatory Services Class of affiliate costs: Project F3PPE9981S (Integrated Energy Management for ESI) for a disallowance of $171,032. Dr. Szerszen testified that these costs were incurred for the implementation, coordination, and promotion of demand side and supply side management and energy efficiency programs. But, she stated, these costs should instead have been recovered through ETI' s Energy Efficiency Cost Recovery Factor (EECRF) Rider and, as such, it is inappropriate to recover these costs through affiliate billings in base rates. 818 ETI witness May testified that recovery of these costs through base rates rather than through the EECRF Rider is appropriate because these activities are not subject to an active ETI energy efficiency program. These activities are more in the nature of general research and development activities that help drive the Company's strategy on these topics, such as the timing of implementing related programs. In the meantime, until these activities result in an actual program proposal, these are legitimate known and measurable costs that the Company has incurred and should then be recovered from retail customers. 819 At the hearing, Mr. May further explained that the costs in this project code are labor costs that are "not really consistent" with the energy efficiency rule, but instead involve "primarily costs of investigating" potential future activities (such as smart meters and electric vehicle chargers) that are generally not consistent with the energy efficiency rider. 820 ETI witness Considine also addresses this issue from a regulatory accounting perspective. He testified: "Because these are not costs that must be, or are currently being recovered through the EECRF, they are not double recovered and should be included in the Company's cost of service." 821 According to 818 OPC Ex. 1 (Szerszen Direct) at 69-70. 819 ETI Ex. 57 (May Rebuttal) at 30-31. 820 Tr. at 1929-1930 and 1934-1935. 821 ETI Ex. 46 (Considine Rebuttal) at 36. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE241 PUC DOCKET NO. 39896 ETI, the costs in this project code, therefore, are not costs that should or can be recovered through ETI's EECRF Rider. This is a close call. The Commission's Energy Efficiency Rule places limits on the amount of research and development costs a utility may recover, 822 which supports the argument that the costs should be included in the EECRF. Further, it appears to the ALls that research and development costs, by their very nature, do not relate to an active program, which negates many of the arguments advanced by ETI witnesses May and Considine. In the end, the ALl s believe that these costs should be included in the EECRF. Accordingly, the AUs recommend the Commission disallow costs in the amount of $171,032 relating to Project F3PPE9981S. 0. Retail Operations Class Dr. Szerszen challenged three project codes that are primarily within ETI' s Retail Operations Class of affiliate costs: (1) F5PPICCIMG (ICC - "Image" Message) for a disallowance of $3,912; (2) F3PPR56640 (Wholesale - EGS-TX) for a disallowance of $229,938; and (3) F3PPR56920 (Wholesale - All Jurisdictions) for a disallowance of $333. 1. Project F5PPICCIMG (ICC-"Image" Message) Project Code F5PPICCIMG (ICC-"lmage" Message) is one of the project codes that Dr. Szerszen testified should be disallowed because ETI is a monopoly and Texas ratepayers should not have to pay for corporate image costs. 823 Ms. Tumminello testified that the costs are for advertising activities that are of a good will or institutional nature, which is primarily designed to improve the image of the utility or the industry, including advertisement which inform the public concerning matters affecting the Company's operations, such as, the costs of providing service, the Company's efforts to improve the quality of service, the Company's efforts to improve and protect the environment. According to FERC, such 822 P.U.C. SUBST. R. 25.181(i). 823 OPC Ex. 1 (Szerszen Direct) at 66. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE242 PUC DOCKET NO. 39896 costs are properly includable in FERC Account 930.1 and are recoverable. According to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the recoverability of these costs. 824 OPC provided little support for its claim that costs covered by these project codes should not be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers should not be charged with such costs. ETI did provide the testimony of Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and are, therefore, recoverable. In the end, the weight of the evidence is in ETI's favor. The AUs recommend the Commission reject OPC' s contention that costs covered by these project codes are not recoverable. 2. Projects F3PPR56640 (Wholesale • EGS-TX) and F3PPR56920 (Wholesale • All Jurisdictions) As to Projects F3PPR56640 and F3PPR56920, Dr. Szerszen stated that these costs are associated with assisting ETI' s wholesale customers in evaluating alternative energy supply and demand options and that ETI' s retail customers should not be charged for expenses associated with ETI' s wholesale customers. 825 ETI witness Stokes noted that ETI has allocated costs to its single large wholesale customer through its jurisdictional allocation in this rate case and, therefore, to disallow the costs in these two project codes would essentially result in a double disallowance of those costs. She also explained that the costs were properly allocable to ETI (keeping in mind that ETI then allocated costs to this customer) as reasonable and necessary due to the need to have staff on hand to handle contract negotiations and the like with this large wholesale customer. 826 The AU s are persuaded by ETI' s argument that disallowing the costs associated with Projects F3PPR56640 and F3PPR56920, which are already allocated to ETI' s single large wholesale 824 ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6. 825 OPC Ex. 1 (Szerszen Direct) at 73. 826 ETI Ex. 66 (Stokes Rebuttal) at 6-9. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE243 PUC DOCKET NO. 39896 customer through its jurisdictional allocation, would constitute a double disallowance. Accordingly, the Alls recommend the Commission reject OPC's challenge to these costs. P. Supply Chain Class Dr. Szerszen challenged two project codes that are primarily within the Supply Chain Class: (1) F3PPH54075 (Business Development-TX) for adisallowance of$1,888; and (2) F5PCZSDEPT (Supervision & Support - Supply) for a disallowance of $146. Dr. Szerszen claimed. the costs associated with these project codes should be disallowed because ETI is a monopoly and Texas ratepayers should not have to pay for corporate image costs. 827 Ms. Tumminello testified that the costs are for advertising activities that are of a good will or institutional nature, which is primarily designed to improve the image of the utility or the industry, including advertisement which inform the public concerning matters affecting the Company's operations, such as, the costs of providing service, the Company's efforts to improve the quality of service, the Company's efforts to improve and protect the environment, etc. According to FERC, such costs are properly includable in FERC Account 930.1 and are recoverable. According to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the recoverability of these costs. 828 OPC provided little support for its claim that costs covered by these project codes should not be recoverable, essentially limiting the basis to the contention that ETI is a monopoly. ETI did provide the testimony of Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and are, therefore, recoverable. The AUs go with the weight of the evidence, which is in ETI's favor. The Al.Js recommend the Commission reject OPC's contention that costs covered by these project codes are not recoverable. 827 OPC Ex. 1 (Szerszen Direct) at 66. 828 ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6. SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE244 PUC DOCKET NO. 39896 Q. Transmission and Distribution Support Class Dr. Szerszen challenged three project codes that are included within the Company's Transmission and Distribution Support Class of affiliate costs: (1) F3PCT53130 (Operations Manager, Claims Management) for a disallowance of $42,287.50; (2) F3PCTDAMAG (Damage Claims Of Entergy Property) for a disallowance of $5,555; and (3) F3PCTPUBLC (Public Claims) for a disallowance of $3,968. Dr. Szerszen's rationale for disallowing 50 percent of the costs in each of these codes is the same. She believes that ETI' s property damage and workers compensation claims should be direct billed instead of allocated through a customer count-based allocator; managerial and supervisory costs should be allocated to the jurisdictions based on the jurisdictional direct charges; and the Company has not met its burden of proof as to these charges. 829 Ms. Tumminello addressed Project F3PCT53130, stating that workers' compensation claims are tracked by jurisdiction as Dr. Szerszen suggested, and are the basis for billing method COMCLAIM. Project F3PCTWCOMP is used to capture the costs of workers' compensation claims, and bills to both regulated and non-regulated affiliates. Project F3PCT53130 captures costs that are primarily for the oversight of the Entergy Companies' Claims Management organization as it relates to property damage and liability. These services benefit only the companies that serve retail electric and gas customers. Since only the regulated utility operating companies (and not the non- regulated companies) serve retail customers, it is appropriate to bill these costs to the regulated companies based on their pro-rata share of total customers. 830 Projects F3PCTDAMAG and F3PCTPUBLC are addressed by ETI witness Corkran. With respect to Project F3PCTDAMAG, Mr. Corkran stated that the costs associated with this project are associated with the Public Claims employees in the Claims Management Organization. Those employees pursue the recovery of claims allowed by law when the public inflicts damage to Company property. The costs of this service are allocated among all of Entergy's Operating Companies through billing method CUSTEGOP, which allocates costs based on the number of 829 OPC Exhibit No. l (Szerszen Direct) at 79-80. 830 ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 10. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE245 PUC DOCKET NO. 39896 customers in each Operating Company. Dr. Szerszen claimed that the affiliate costs associated with pursuing those claims should be directly charged to each Entergy Operating Company based on the extent to which each claim pertains to the Operating Company instead of generally allocating the costs to all utility customers. Mr. Corkran testified that the allocation methodology is appropriate because the Public Claims employees provide knowledgeable, centralized, and consistent pursuit of damage claims. The actual monies recovered for damage to ETI' s property are returned to ETI ratepayers as credits against the cost of repairing those damaged facilities, i.e., the recoveries are not allocated pursuant to CUSTEGOP. Only the Public Claims employees' time and overheads are allocated pursuant to CUSTEGOP, which is reasonable and appropriate because the overall time spent by Public Claims employees in pursuing the recovery of claims is driven by the number of gas and electric customers in each Operating Company. 831 With respect to Project F3PCTPUBLC, Mr. Corkran stated that the costs associated with this project are related to Public and Auto Liability employees in the Claims Management Organization. These employees pursue the resolution and settlement of damage claims made against the Operating Companies in a timely and fair manner through denials, negotiations, and payments. Such claims include allegations of damaged appliances due to voltage fluctuation, food loss due to power outages, and damage caused by Company vehicles (e.g., mailboxes, fence posts, and automobiles). This is an important process that ensures that only warranted and justifiable claims are paid. The CUSTEGOP billing method is appropriate because the Public and Auto Liability employees provide knowledgeable, centralized, and consistent resolution of damage claims. The actual payments associated with ETI public damage claims are charged to ETI through the use of other project codes. Only the Public and Auto Liability employees' time and overheads are allocated pursuant to CUSTEGOP, which is reasonable and appropriate because the overall time spent by Public and Auto Liability employees in processing claims is driven by the number of gas and electric customers in each Operating Company. 832 831 ETI Ex. 48 (Corkran Rebuttal) at 13-15. 832 Id. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE246 PUC DOCKET NO. 39896 The explanations that ETI provides for the charges captured by these project codes and the method of allocation employed makes sense to the AUs. In a large organization, it is necessary to have a group of people to process claims efficiently so that economies of scale can be realized; that is what ETI is doing with these project codes. These costs benefit all companies within the Entergy umbrella (or within the regulated entities portion as noted), so the allocation methodology employed is appropriate. The ALls recommend the Commission reject OPC's challenge to the recovery of these costs. R. Tax Services Class Dr. Szerszen proposed a 25 percent ($221,007) disallowance of costs billed to ETI from a single project code in this Tax Services Class: Project Code F3PCF10445 (Entergy Consolidated Tax Services). The costs in this project were incurred in the preparation, research, and other costs associated with Entergy's consolidated tax return. Dr. Szerszen testified that an assets-based allocator is not appropriate for these costs and that the costs in the project should instead be directly billed to each affiliate based on the time spent on preparing that affiliate' s income and expense data. 833 Company witness Galbraith, who sponsors ETI' s Tax Services Class, stated that Dr. Szerszen apparently believes that all costs associated with the preparation of Entergy' s consolidated tax return are captured by this project code and are allocated, when they should be direct-billed. Most of the costs associated with preparation of Entergy' s consolidated tax return, according to Ms. Galbraith, are assigned to other project codes and are direct billed. Ms. Galbraith then explained that: (1) 56 percent of the time that Tax Services spent on the Entergy consolidated tax return were direct billed through other project codes to the affiliates; (2) the project code also captures costs for tax research (both federal and state and local), monthly closing activities not specific to one legal entity, tax training that is not jurisdiction specific, compliance with file retention policy, and administration staff time; and (3) why the assets-based allocator is the best method for allocating these departmental 833 OPC Ex. I (Szerszen Direct) at 63. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE247 PUC DOCKET NO. 39896 costs. According to Ms. Galbraith, the costs captured by this code are not susceptible to direct billing. 834 The AlJs find that Dr. Szerszen did fail to consider that most of the costs of preparing Entergy's tax return are direct billed and that the costs covered by this project code are not susceptible to such a billing, which is why they are allocated. The AlJs, therefore, recommend the Commission reject OPC' s challenge to ETI' s allocation of these costs. S. Transmission Operations Class Dr. Szerszen challenged three project codes that are primarily within the Transmission Operations Class: (1) F3PPTDHY19 (Dept. of Justice Investigations) for a disallowance of $765; (2) F3PPTREORG (Transmission Re-Organization) for a disallowance of $3,661; and (3) F3PPF30211 (ESI Transmission Bldg (Reclassification)) for a disallowance of $229,991. 835 Dr. Szerszen addressed Project F3PPTREORG (Transmission-Reorganization) and testified that costs covered by this project were incurred in 2009 and 2010 and, therefore, are not recurring. 836 Ms. Tumminello responds that, while these particular costs do not recur every year, they are representative of normal recurring utility operations and do recur as necessary and, as such, they should not be disallowed. 837 Dr. Szerszen testified that Project F3PPF30211 (ESI Transmission Bldg.) captures interest costs after the ESI transmission building was placed in service. She contends that the costs are reclassified pre-Test Year payments and post-Test Year interest costs that are not known and measureable. 838 Ms. Tumminello testified that Dr. Szerszen has misconstrued accounting entries. 834 ETI Ex. 26 (Galbraith Direct) at 10-12. 835 Project F3PPTDHY 19 (Dept. of Justice Investigations) was discussed in Section VIII.L. (Legal Services Class) and will not be repeated here 836 OPC Ex. l (Szerszen Direct) at 54, Schedule CAS-8. 837 ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 1. 838 OPC Ex. 1 (Szerszen Direct) at 71. SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE248 PUC DOCKET NO. 39896 She explains that these charges capture 12 months of interest payments and the annual bond fee incurred only during the Test Year. 839 The AUs find that the costs associated with Project F3PPTREORG are representative of costs that recur every year and should not be disallowed. It appears to the AU s that Dr. Szerszen did misconstrue accounting entries in preparing her analysis of Project F3PPF3021 land that the charges in that project capture fees paid during the Test Year. Accordingly, the ALls recommend that OPC's proposed disallowance be denied. T. Treasury Operations Class Dr. Szerszen challenged three project codes that are primarily within the Treasury Operations Class: (1) F5PCZZI07P (Directors & Officers (EIM)) for a disallowance of $14,483; (2) F3PCF25300 (Daily Cash Mgt Activities) for a disallowance of $7,286; and (3) F3PCF26022 (Financing & Short Term Funding) for a disallowance of $96,700. With respect to Project F5PCZZ107P (Directors & Officers (EIM)), Dr. Szerszen testified that the directors and officers liability insurance subject to this project code is primarily aimed at benefiting shareholders, rather than ratepayers and, because ETI does not manage ESI' s operations, it should not be responsible for indemnifying against shareholder lawsuits. 840 ETI witness McNeal stated that ESI provides essential administrative and operational services to ETI on a daily basis. To do this, it must employ (and retain) qualified officers and directors. These individuals must be assured that they can make reasoned decisions without fear of personal liability and the manner to provide them this assurance is to purchase director's and officer's liability insurance. Because ETI benefits from the services provided by the officers and 839 ETI Ex. 69 (Tumminello Rebuttal) at 15. See also Ex. SBT-R-5. 840 OPC Ex. 1 (Szerszen Direct) at 59. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE249 PUC DOCKET NO. 39896 directors, ETI argues, it is appropriate to allocate a portion of the cost of the director's and officer's liability insurance to ETI. 841 Dr. Szerszen addressed Projects F3PCF25300 (Daily Cash Mgt Activities) and F3PCF26022 (Financing & Short Term Funding), contending that these projects are duplicative of ETI-specific financing and cash management activities; that these costs should be borne by Entergy shareholders; and that the bank accounts-based and level of service-based allocators applicable to this projects are not appropriate. 842 ETI responds that Project F3PCF25300 captures costs for activities performed by the Cash Management Department for work associated with maintaining bank relationships, bank fee analysis, administrative of bank systems and controls, and all other banking and cash management activities that are general in nature. These are not specific to any one company, but are applicable to all of the companies within the umbrella of the Entergy corporate family. There are Company-specific activities that are charged directly to ETI under different project codes, and this constitutes the majority of financing and cash management activities during the Test Year. For Project F3PCF25300, the costs are driven by cash management products and services delivered to all the Entergy companies. Because the number of transactions executed on behalf of each Entergy company is directly related to the number of bank accounts by company irrespective of account size, billing method BNKACCTA, which allocates costs based on the number of open bank accounts is, according to ETI, the appropriate method to allocate the costs of these services. 843 With respect to Project F3PCF26022, ETI explains that the project code captures costs for managing Entergy companies' liability portfolios comprised of Entergy company securities, bank lines, and project financings. The work is performed for the benefit of all companies under the Entergy corporate umbrella, not just ETI and is not duplicative of services performed for ETI. When work is performed by ESI personnel that relates specifically to ETI, then ETI is charged directly 841 ETI Ex. 61 (McNeal Rebuttal) at 7-8. 842 OPC Ex. l (Szerszen Direct) at 74-75, Ex. CAS-15. 843 ETI Ex. 61 (McNeal Rebuttal) at 3-6; Tr. at 546. SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE250 PUC DOCKET NO. 39896 under a different project code. The services include analyzing and supporting general capital structure policy, developing and analyzing general financial policies, investigating and evaluating financing options generally that might prove beneficial for any or all Entergy companies, including ETI, and facilitating ongoing administration related to all Entergy Operating Company financings. Accordingly, ETI argues that it is appropriate to allocate a share of those costs to ETI. The costs of this project are driven by the level of service needed to complete the project or activity. Allocator LVSVCAL allocates costs based upon the overall service level ofESI. This allocation is appropriate because ESI is providing the service and no one Operating Company alone benefits from the services provided under this project code. 844 OPC appears to have taken too narrow a view with respect to these project codes. First, it appears that where services are performed solely for ETI, they are charged to ETI through specific project codes. The project codes that OPC challenges are for company-wide services that are partially allocated to ETI. It is logical to assume that a certain level of services can be performed more efficiently at a company-wide level and that Texas ratepayers will benefit by paying only the allocated portion of those costs, as is done in these cases. The allocators chosen by ETI appear to reasonably reflect the cost-causation. Therefore, the AUs recommend that OPC's challenge be rejected. U. Utility and Executive Management Class OPC challenges five project codes that are primarily within the Utility & Executive Management Class: (1) F3PPCCSO 10 (Climate Consulting Services) for a disallowance of $19,821; (2) F3PCCPM001 (Corporate Performance Management) for a disallowance of $173,867; (3) F3PCC31255 (Operations-Office of the CEO) foradisallowanceof$372,919; (4) F3PPCA0001 (Chief Administrative Officer) for a disallowance of $177,156; and (5) F3PPC00001 (Chief Operating Officer) for a disallowance of $74,485. 844 ETI Ex. 61 (McNeal Rebuttal) at 2-3; Tr. at 547-548. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE251 PUC DOCKET NO. 39896 As to the first, Project F3PPCCS010 (Climate Counseling Services), Dr. Szerszen testified that these costs are incurred for the development of company-wide environmental policies, procedures, and programs; that expenses are improperly allocated to the subsidiaries based on each company's fossil operating capacity; and, as a result, the non-regulated affiliates are not allocated any environmental initiative expenses. She therefore recommended that 50 percent of this project's costs be disallowed. 845 ETI witness Stokes addressed Dr. Szerszen' s challenge to this project. Ms. Stokes explained that although nuclear-related environmental projects are being pursued, they are not being pursued using the project code referenced by Dr. Szerszen in her challenge. The costs for non-regulated affiliates are charged to projects not included in ETI' s affiliate costs in this case. Non-regulated affiliates use project codes specific to their businesses to maintain a separation of costs between regulated and non-regulated Entergy subsidiaries. 846 For the remaining four project codes in this class, Dr. Szerszen stated that executive management is primarily concerned with overall corporate functions rather than issues for any one specific subsidiary, and there is no relationship between an assets-based allocator and executive management. 847 ETI responds to these arguments by stating that the functions covered by these project codes relate to the oversight of all system operations and the stewardship of corporate assets and that because ETI is part of a corporate group, the allocated charges associated with these services are relevant to ETI as part of that group of companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the cause of the costs incurred, in that, services provided relate to the stewardship of all the corporation's assets. 848 845 OPC Ex. 1 (Szerszen Direct) at 62. 846 ETI Ex. 66 (Stokes Rebuttal) at 5. 847 OPC Ex. l (Szerszen Direct) at 56, 60. 848 ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE252 PUC DOCKET NO. 39896 A corporation cannot function without executives, who are charged with the responsibility of overseeing, among other things, the assets of the corporation. This is an important function that Dr. Szerszen did not acknowledge in her testimony. The utility and executive management class costs that she challenges are reasonable and necessary costs that are allocated to ETI based on a logical allocator - the assets the executives manage. The ALT s recommend that OPC' s challenge be rejected. IX. JURISDICTIONAL COST ALLOCATION [Germane to Preliminary Order Issue No. 13] Jurisdictional cost allocation involves the proper method for allocating production costs between ETI' s Texas retail customers and its wholesale customers, which are subject to FERC jurisdiction. During the Test Year, ETI provided electric service to retail customers and to three wholesale customers-including ETEC-under service agreements and rates approved by FERC. ETEC is a partial requirements customer, and it will be ETI's only wholesale customer during the Rate Year. ETI estimated its cost of serving wholesale customers in a jurisdictional separation study that split ETI' s cost of service between retail and the wholesale jurisdictions. 849 To calculate the wholesale cost allocation factor, ETI proposed the use of 150 MW for the wholesale load. This results in a retail production demand allocation factor of 95.3838 percent. The 150-MW load represents the contractual minimum amount of capacity for which ETEC is obligated to pay under its partial requirements agreement. No party contests this aspect of ETI' s proposed allocation of costs between retail and wholesale customers. 850 However, Cities contest the type of allocation methodology used to assign demand-related (fixed) production costs to each jurisdiction. In this proceeding, ETI used the A&E 4CP allocation method. Although this is the same methodology ETI used in this proceeding's class cost-of-service 849 Cities Ex. 4 (Goins Direct) at 4. 850 ETI Ex. 7 (May Direct) at 23-24. Ms. Talkington used the 150 MW number sponsored by Mr. May, and the associated energy use, to calculate the jurisdictional allocation factor. ETI Ex. 22 (Talkington Direct) at 11-12. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE253 PUC DOCKET NO. 39896 study (to assign demand-related production costs to each retail customer class), ETI used a different methodology - 12 Coincident Peak (12CP) - in its last rate case to assign costs between jurisdictions. 851 A. A&E4CP Kroger witness Kevin C. Higgins explained the A&E 4CP method: [T]he Average and Excess Demand method uses an average demand or total energy allocator to allocate that portion of the utility's generating capacity that would be needed if all customers used energy at a constant 100 percent load factor. The cost of capacity above average demand is then allocated in proportion to each class's excess demand, where excess demand is measured as the difference between each class's individual peak demand and its average demand. In this manner, the incremental amount of production plant that is required to meet loads that are above average demand is assigned to the users who create the need for the additional capacity.... the A&E/4CP variant . . . uses 4 CP to measure excess demand, whereas the conventional version uses class non-coincident peak ....852 ETI witness Myra L. Talkington also explained that the A&E 4CP method, noting that ETI' s coincident peak demand is measured for the months of June through September. Ms. Talkington recommends the A&E 4CP allocation because it "reasonably reflects the mix of the Company's customers and their respective electrical load characteristics and the relative cost incurred to serve such loads." 853 She also believes this allocation methodology provides a reasonable balance between the contribution to the system peak and energy requirements. 854 As noted above, ETI's use of A&E 4CP is a change from the 12CP methodology it used when it operated within two states. Ms. Talkington testified that 12CP was appropriate in the past because System Agreement costs were allocated between Entergy Operating Companies using 12CP. The Texas retail portion of the production costs were then allocated between the retail classes using 851 Cities Ex. 4 (Goins Direct) at 10. 852 Kroger Ex. 2 (Higgins Cross Rebuttal) at 3 (footnotes deleted). 853 ETI Ex. 23 (Talkington Direct) at 6; OPC Ex. 6 (Benedict Direct) at 17. 854 ETI Ex. 23 (Talkington Direct) at 6. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE254 PUC DOCKET NO. 39896 the A&E 4CP methodology (as ETI is doing in this case). However, according to Ms. Talkington, now that ETI operates in only one state, no jurisdictional allocation among states is necessary; therefore, only one allocation methodology, i.e., A&E 4CP, should be used to allocate production costs between the retail classes and the wholesale jurisdiction. Ms. Talkington testified that the A&E 4CP methodology factors in year-round demand through the average and excess function and also 855 matches the allocator used to allocate costs within the retail class. Cities opposes the use of A&E 4CP and suggest a 12CP methodology is preferable. Commission Staff does not oppose ETI' s use of A&E 4CP. No other party takes a position on this issue. B. 12CP Thel2CP methodology allocates production capacity costs in proportion to each class's demands that occur on the date and time of ETI's system peak in each of the 12 months. 856 Cities believe it is more appropriate for ETI to allocate fixed production costs between the wholesale customers and Texas retail customers using 12CP. Cities witness Dennis W. Goins testified that the 12CP approach is consistent with the cost-of-service approach FERC typically uses to allocate demand-related production costs reflected in wholesale rate schedules, and it is consistent with the assignment of MSS-1 costs (as well as MSS-2 transmission costs) to ETI under the Entergy System Agreement. Dr. Goins reviewed ETI' s Rate Year purchased power capacity costs month by month. He determined that ETI' s heavy reliance on capacity purchases to serve retail and wholesale load, and the relative stability of those projected monthly purchased power capacity costs, suggest that the 12CP method should properly split ETI' s demand-related production costs between the Texas retail and wholesale jurisdictions.857 855 ETI Ex. 67 (Talkington Rebuttal) at 6-7. 856 TIEC Ex. 3 (Pollock Cross Rebuttal) at 26. 857 Cities Ex. 4 (Goins Direct) at 10-12. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE255 PUC DOCKET NO. 39896 Dr. Goins calculated Test Year 12CP allocation factors for the Texas retail and wholesale jurisdictions, and provided them to Cities witness Karl Nalepa for inclusion in his jurisdictional separation study. He determined the following: 858 Jurisdiction A&E4CP 12CP Texas Retail 95.3838% 94.6208% Wholesale 4.6162% 5.7923% Total 100% 100% In making this calculation, Dr. Goins used a loss-adjusted 150 MW (ETEC's monthly billing MW) as a proxy for the 12 monthly CPs. In his view, the 150 MW is indicative of ETI' s capacity obligations to ETEC, and it reflects known and measurable changes compared to test-year wholesale CPs (which would include CPs for wholesale customers that ETI no longer serves). 859 Cities point out that ETI previously allocated production costs to the wholesale jurisdiction on a 12CP basis. ETI first requested that the Commission change the 12CP method in Docket No. 37744. 860 According to Cities, ETI's request to change the 12CP methodology in Docket No. 37744 is significant because ETI's wholesale load consisted of Brazos Electric Cooperative, Inc. (Brazos) and ETEC. The Brazos contract assigned Brazos' share of ETI' s production costs based upon a 12CP allocator. Thus, contends Cities, all costs that would have been over-allocated to retail customers would have been pocketed by ETI (if the 12CP allocator had changed). Cities argue that ETI's request to deviate from its approved 12CP allocator will result in retail customers subsidizing production costs. Dr. Goins calculated that the 12CP allocation factor for ETI's wholesale jurisdiction is approximately 5 .3 8 percent versus 4.62 percent under the A&E 4CP method. 861 Cities conclude that retail customers will subsidize the difference between the two allocators, which is 858 Cities Ex. 4 (Goins Direct) at 12. 859 Cities Ex. 4 (Goins Direct) at 10-12. 860 The parties in that docket stipulated the majority of issues in the case, including issues relating to jurisdictional allocation. 861 Cities Ex. 4 (Goins Direct) at l 1-12. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE256 PUC DOCKET NO. 39896 0.76 percent. Because the allocation is applied to all production costs, including purchased power capacity costs, the 0.76 percent difference is significant, contend Cities. According to ETI, Cities' arguments are based on a non-existent situation-the provision of service to Brazos-and should be rejected. The AUs acknowledge that ETI is no longer serving Brazos. Dr. Goins noted such in his testimony. Rather, the basis for his recommendation was: (1) the 12CP approach is consistent with FERC's wholesale rate allocation; (2) the 12CP method is used to derive each Entergy Operating Company's load responsibility ratio and share of monthly MSS-1 and MSS-2 charges; and (3) ETI' s purchased power capacity costs do not vary significantly month to month. Although Ms. Talkington understood that the A&E 4CP methodology is the same one used to allocate production costs between classes, TIEC witness Pollock noted that it is often not appropriate to use the same allocation method for both jurisdictional and class allocations. He noted that, in jurisdictional separation, allocations are between retail and wholesale entities, with wholesale subject to FERC regulation. 862 ETI did not fully explain why A&E 4CP is the best methodology for allocation production costs between the retail and wholesale jurisdictions. Dr. Goins' and Mr. Pollock's testimonies were ultimately more persuasive on this issue. Accordingly, the AUs recommend the use of 12CP to allocate capacity-related production costs between the retail and wholesale jurisdictions. X. CLASS COST ALLOCATION AND RATE DESIGN [Germane to Preliminary Order Issue No. 1] ETI witness Talkington testified regarding the allocation methods for each of the major function/classification cost categories used in the Company's retail class cost-of-service study. Ms. Talkington also sponsors ETI's proposed rate design. Contested issues are set out below. 862 TIEC Ex. 3 (Pollock Cross Rebuttal) at 29. The ALJs acknowledge that Mr. Pollock does not contest ETI's use of the A&E 4CP jurisdictional allocation methodology-rather, his testimony was explaining why 12CP is not appropriate as an allocator among the different customer classes. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE257 PUC DOCKET NO. 39896 A. Renewable Energy Credit Rider [Germane to Preliminary Order Issue No. 19] The Legislature has established a goal for the installation of an additional 5,000 MW of generating capacity from renewable energy technology. It also set out annual goals for electric utilities to meet on a cumulative basis in order to encourage the development of renewable energy generation in Texas: A utility may meet its annual goals by installing generation, by purchasing capacity based on renewable energy technology, or by purchasing sufficient renewable energy credits (RECs). 863 1. ETl's Proposed Cost Recovery Staff witness William B. Abbott explained that the Company currently recovers its REC costs through base rates. Each credit represents one megawatt-hour (MWh) of renewable energy that meets certain criteria set forth in P.U.C. SUBST. R. 25.l 73(e), and these credits can be traded among participants in the Texas market. ETI proposes to remove these costs from base rates and implement a REC Rider to recover its projected REC costs. After the initial rider is established, the REC Rider would be reset annually to recover projected REC costs for the upcoming year, adjusted by any past over- or under-recovery and any revenue-related expenses. 864 With the introduction of the REC Rider, ETI would withdraw its current Renewable Portfolio Standard Calculation Opt-Out Credit Rider, which provides a credit to offset the base rate REC costs for certain customers who are exempt from paying REC costs. These customers would instead be exempt from charges under the proposed REC Rider. 865 ETI suggests that a rider is necessary because the level of REC costs incurred from year to year is not known, and the cots are unknowable and very volatile. ETI witness Heather G. LeBlanc 863 PURA §39.904(a) and (b). 864 See ETI Ex. 31 (LeBlanc Direct) at 26. 865 Staff Ex. 7 (Abbott Direct) at 11-12. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE258 PUC DOCKET NO. 39896 testified that certain customers can opt out, and a rider is the most efficient manner to administer such opt out. 866 Initially, ETI based its rates for the proposed rider on the Company's Test Year renewable energy credit costs, which were incurred on a Texas retail basis for the 12 months ending June 30, 2011. ETI requested $623,303 and, after applying the revenue-related expense factor of 1.01307, proposed a revenue requirement of $631,450. 867 In rebuttal testimony, Ms. LeBlanc stated that the Company's proposal should be updated to reflect the most current data available. She stated that "events" since the Company's initial filing in November 2011 caused costs for the Company to increase. 868 She calculated an updated amount of $1,145,043, which, when the revenue-related expense factor is applied, results in an updated revenue requirement of $1,160,008. 869 She believes that the updated amounts further support the Company's position that REC costs are volatile. 2. Opposition to ETl's Proposal Cities, OPC, State Agencies, and Commission Staff oppose ETI' s proposed REC Rider. State Agencies argue that ETI's proposed REC Rider should be rejected because it deviates from the Commission's ratemaking policies and is inconsistent with PURA State Agencies witness Kit Pevoto testified that the proposed rider is not appropriate because: (1) the rider is piecemeal ratemaking, which deviates from the Commission's traditional ratemaking policies and is inconsistent with PURA; (2) the reconciliation (true-up) process in the proposed tariff is not specifically provided for by PURA or PUC rule, or required to implement the REC process; (3) the redetermination of rates in the proposed annual filings would be based on projected or estimated costs, rather than historical test year costs; which is not in compliance with PURA or the Commission's rules; and (4) ETI has not justified the need to have a rate recovery for REC costs 866 ETI Ex. 31 (LeBlanc Direct) at 25. 867 Id. at 24. This amount is then divided by all non-transmission level kWh sales. 868 ETI Ex. 55 (LeBlanc Rebuttal) at l 0-11. 869 Id. at 11. This amount is then divided by all non-transmission level kWh sales. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE259 PUC DOCKET NO. 39896 outside of the traditional PURA base rate recovery. Ms. Pevoto explained that the traditional test year cost of service ratemaking process, including regulatory lag, helps to match costs and revenues and to provide incentives that balance the utility's and its customers' interests. The proposed REC rider deviates from the traditional PURA rate-setting because it allows the Company to reset its rates automatically each year without going through a comprehensive rate proceeding. In her view, the rider would eliminate the regulatory lag incentive for ETI to prudently manage these costs because the rider allows for annual cost recovery adjustments. Ms. Pevoto observed that various provisions in PURA authorize riders for collection of other expenses, but no such provision exists for recovery of REC expenses, even though the Legislature mandated that utilities be responsible for a certain level of REC MWs. And she noted that if ETI's REC expenses increase due to increases in total 870 REC MW requirements, ETI can request to include those increased costs in a future rate case. In reference to Ms. LeBlanc's rebuttal testimony that "events" caused ETI's REC costs to increase, State Agencies contend that ETI may have paid more for RECs during the Test Year because it contacted suppliers only after the REC requirement was mandated. ETI acknowledged that RECs were in the $1.10 to $1.25 range at the beginning of the year and then appreciated to over $2.00 and peaked out at $2.55 in the first quarter of 2012. Moreover, one of the largest REC suppliers unexpectedly withdrew its offers in March of 2011, which also led to price increases. March 31 is the end of the compliance period, and the deadline may increase the volume of purchases, which can add to price increases. 871 State Agencies note that ETI did not participate in the competitive REC market until February 2012 and bought its RECs near the peak price. State Agencies contend that only Test Year costs of $623,303 should be included in base rates. Cities witness Karl Nalepa also opposed the REC Rider. He testified that the Commission should not permit ETI to single out REC costs from base rates because it presented no evidence that these costs should be treated differently than they are now. He added that RECs are not related to fuel so much as they are related to retail sales and plant output. In his opinion, the Test Year amount 870 State Agencies Ex. 2 (Pevoto Direct) at 6, 8-1 l. 871 State Agencies Ex. 12, RFI. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE260 PUC DOCKET NO. 39896 for REC of $633,985 should be included in base rates. 872 Cities witness James Z. Brazell also testified that ETI currently recovers a large portion of its revenues through non-fuel piecemeal riders. While he believes some riders are necessary and appropriate, ETI' s general movement of cost recovery from base rates to riders (as evidenced in this proceeding) is inconsistent with PURA and the prohibition against piecemeal ratemaking. 873 OPC also opposed ETI' s proposed REC Rider on the basis that it constitutes piecemeal ratemaking. OPC witness Nathan A. Benedict noted that in Project No. 35628, the Commission rejected alternative mechanisms for the recovery of REC costs but reserved the right to consider the issue at a later date. 874 He stressed that, when rejecting alternative recovery mechanisms for REC costs, the Commission recognized that REC costs are variable, that the purchase of RECs is mandated by law, and that certain customers can opt out of the Renewable Portfolio Standard program. Thus, in Mr. Benedict's view, the Commission has already rejected the arguments advanced by ETI here. He added that ETI did not indicate a negative and substantial impact as a result of transmission customers opting out of the Renewable Portfolio Standard program, and ETI appears to be currently administering the program effectively without REC Rider. In short, Mr. Benedict concluded that costs related to renewable energy credits should be recovered through base rates, and ETI's current opt-out rider should continue as the vehicle for ETI to handle transmission-level opt-outs. 875 Commission Staff also opposes ETI' s request, stating that it amounts to unauthorized piecemeal ratemaking that should be disallowed. In Staffs view, the existing opt-out rider should be maintained but updated to reflect the test year data used to set the ETI' s base rates. Because ETI' s 872 Cities Ex. 6 (Nalepa Direct) at 30-32. Mr. Nalepa' s figure of $633,985 differs from tliat the figure of $623,303 found in ETI's testimony at ETI Ex. 31 (LeBlanc Direct) at 24 and State Ex. 9. 873 Cities Ex. l (Brazell Direct) at 14-16. 874 OPC Ex. 6 (Benedict Direct) at Ex. NAB-8, Project No. 35628, Rulemaking Relating to Industrial Customer Opt-Out of Renewable Portfolio Standard, Order at 6 (December 4, 2008). 875 OPC Ex. 6 (Benedict Direct) at 37-41. ETI currently has a Renewable Portfolio Standard Calculation Opt-Out Credit Rider to credit REC costs collected in base rates from transmission level customers who have opted out of the program. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE261 PUC DOCKET NO. 39896 proposed rider would include a true-up provision that would guarantee recovery of all of its REC costs, Staff witness Abbott testified that it would violate PURA § 36.051, which provides the utility a reasonable opportunity to earn a reasonable return on invested capital but does not guarantee full recovery of all costs. Mr. Abbott acknowledged that the Legislature has authorized the recovery of certain specific costs outside of base rates, but no such authorization exists for the recovery of REC costs. 876 In addition, Mr. Abbott criticized the proposed REC rider because in the future it would allow prospective recovery of estimated REC costs. He believed that such an arrangement would eliminate any regulatory lag and thus eliminate any incentive for ETI to minimize the costs of purchasing the required RECs. 877 Mr. Abbott also pointed out that the proposed rider contains a single rate for all customer classes and includes a "revenue related expense factor," which increases the overall rider revenue requirement to, in part, account for projected uncollectable bills. 878 This would shift the costs of uncollectable bills from customer classes with greater bad debt onto customer classes with lower bad debt. Further, Mr. Abbott stated, the proposed true-up portion of the REC Rider would eliminate the need for a bad debt factor, as any actual under-collected amounts would carry forward and could be recovered in future filings. Also, the single rate could result in cost-shifting between customer classes, as over- or under- recoveries resulting from billing determinant forecast error would vary by customer class. Finally, Mr. Abbott stated, the ETI's proposed billing determinants are based on a historical year. But if load grows over the long term, 876 Staff Ex. 7 (Abbott Direct) at 12-13. Mr. Abbott cites to PURA§§ 36.203 (Fuel Cost Recovery), 36.205 (Purchased Power Cost Recovery), 36.209 (Transmission Cost Recovery), 36.210 (Distribution Cost Recovery), 39.107(h) (Advanced Meter Deployment Surcharge), 39.461 (Hurricane Reconstruction Costs), 39.905(b)(l) (Energy Efficiency Cost Recovery). 877 While the price of RECs at any point in time are set by the market, presumably a purchaser has some ability to seek relatively better terms-such as making an effort to accurately forecast the number of credits required and perhaps purchasing or contracting to purchase available credits beforehand if prices are favorable, seeking volume discounts, banking excess credits when prices are favorable, etc. 878 Schedule Q-8.8 at 45.4. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE262 PUC DOCKET NO. 39896 this will lead to persistent over-recovery of the REC Rider revenue requirements, as Rate Year billing determinants will tend to exceed the historical billing determinants systematically. 879 Based on these concerns, Mr. Abbott recommended that the Commission deny ETI' s request for a REC Rider, and that the ETI's Test Year REC costs of $623,303 be included in base rates. Additionally, he recommended that the Renewable Portfolio Standard Calculation Opt-Out Credit Rider should be maintained; however, the credit rates should be updated to reflect the Test Year data used to set ETI' s base rates. In the alternative, if the Commission approves the REC Rider requested by ETI, Mr. Abbott recommended the following changes from the Company's request: The REC Rider should be set every year to collect the previous year's actual REC costs (instead of projected REC costs), plus any over- or under- recovery from prior periods. The previous year's actual REC costs should be allocated to each customer class based upon each class's actual energy usage over the time period for which the RECs were acquired. Any over- or under- recovery balances should be tracked by each customer class, and thus a separate REC Rider rate should be calculated for each customer class based on that class's allocated REC costs adjusted by that class's over- or under- recovery balance. The REC Rider rates should be calculated using billing determinants based upon ETI's best forecast of each customer class's energy usage over the rider's Rate Year.880 3. ETl's Response ETI contends that adoption of the rider does not result in piecemeal ratemaking because these are the types of costs that the Company cannot control. Ms. LeBlanc believes that there is a greater 879 Staff Ex. 7 (Abbott Direct) at 13-14. 880 Staff Ex. 7 (Abbott Direct) at 14-15. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE263 PUC DOCKET NO. 39896 risk of over-recovery of REC costs through base rates than there would be under the proposed rider. 881 As to the issue that the Company would be disincentivized to purchase RECs at an appropriate time, ETI claims that the proposed rider has a true-up mechanism that would allow for review. ETI disputes State Agencies' claims that ETI could have purchased RECs at a lower level at other points in the year, stating there is no evidence that the Company could have bought RECs at a lower level at other points in the year. Finally, ETI takes issue with the parties' argument that there is no statutory recovery for REC costs outside of base rates. ETI argues that there is no statutory authority requiring the Company to refund costs to opt-out industrial customers. According to ETI, no explicit statutory authority is necessary, and the parties have failed to establish that any harm would result from implementation of the rider. 4. ALJs' Analysis The AU s are persuaded by the testimonies of Staff and intervenor witnesses Pevoto, Nalepa, Abbot, Benedict, and Brazell that ETI's proposed REC rider should be rejected. The testimony supports a finding that adoption of the rider results in piecemeal ratemaking. ETI' s argument that costs are volatile and, therefore, should be isolated and recovered in a manner similar to an annual fuel factor filing was not supported by sufficient evidence. Additionally, the AUs agree that the proposed rider eliminates any incentive for ETI to minimize the costs of purchasing the required RECs. ETI proffered unconvincing argument and insufficient evidence that standard cost recovery was insufficient for ETI to recover its total REC costs and a reasonable return. The AU s further find that the Test Year expense of $623 ,303 should be used for setting rates in this case. 882 ETI failed to proffer sufficient evidence and argument to support any increase to its 881 ETI Ex. 55 (LeBlanc Rebuttal) at 11. 882 This is the amount referenced in Ms. LeBlanc' s testimony at ETI Ex. 31 at 24 and confirmed in State Agencies Ex. 9. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE264 PUC DOCKET NO. 39896 initial request through rebuttal testimony. As recommended by Staff witness Abbott, the Renewable Portfolio Standard Calculation Opt-Out Credit Rider should be maintained, with an adjustment to the credit rates to reflect the Test Year data used to set ETI' s base rates. B. Class Cost Allocation [Germane to Preliminary Order Issue No. 14] A cost-of-service study is an analysis used to determine the responsibility for a utility's costs for each customer class. Thus, it determines whether the revenues a class generates cover that class's cost-of-service. A class cost-of-service study separates the utility's total costs into portions incurred on behalf of the various customer groups. Most of a utility's costs are incurred to jointly serve many customers. For purposes of rate design and revenue allocation, customers are grouped into homogeneous classes according to their usage patterns and service characteristics. The parties generally agreed that ETI's cost-of-service study comported with accepted industry practices, but some parties had issues with specific items discussed below. 1. Municipal Franchise Fees Municipal Franchise Fees (MFF) are charges for a utility's use of municipal rights-of-way. The charges are levied by municipalities based on the amount of electricity sold within the municipal boundaries. They are also referred to as street rental taxes. The MFF charged to ETI are based on ordinances passed by the cities in which ETI makes retail sales. Different cities have enacted different levels of MFF on in-city kWh sales, ranging from 0.0956¢ to as much as 0.2644¢ per kWh. 883 For the portion of fees ETI collects through base rates, ETI proposes to allocate among customer classes based on customer class revenues relative to total revenues. 884 Once MFF costs are 883 TIEC Ex. 1 (Pollock Direct) at 52 and Ex. JP-9. Nineteen cities also charge MFF through separate "Incremental Franchise Fee Recovery" Riders. These incremental MFF are not included in ETI's proposed revenue requirements in this case. TIEC Ex. 1 (Pollock Direct) at 53. 884 Schedule P-13 atlO, lines 32-33; the allocation factor "RSRRTOA-Total" is rate schedule revenue. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE265 PUC DOCKET NO. 39896 allocated to the rate classes, ETI proposes to collect the costs from all customers regardless of their geographic location. 885 ETI proposes the same allocation and collection of MFF in this case as was approved by the Commission in Docket No. 16705, ETI's last litigated rate case. 886 The positions of the parties, as set out in testimony and briefs, are listed below: Party/Precedent l\ilFF Allocation Between Collection of l\ilFF Expenses From: Customer Classes By: ETI Total revenues All customers Cities Total revenues All customers OPC kWh sales in city All customers Staff kWh sales in city All customers TIEC Franchise fee payments in city Only from municipal customers Docket No. 16705 Total revenues All customers (a) MFF Allocation Between Customer Classes Cities and ETI recommend adoption of ETI' s proposal to allocate to customer classes based on total rate schedule revenues, which the Commission approved in Docket No. 16705. ETI notes that it is following Commission precedent, and it opposes the use of different allocation factors for these FERC accounts: Account 408.152, Franchise Tax State; Account 408.154 Franchise Tax Local; and Account 408.163, Street Rental. OPC witness Benedict testified that MFF should be allocated on the basis of in-city kWh sales, without an adjustment for the MFF rate in the municipality in which a given kWh sale occurred. Staff witness Abbot concurs. Stated differently, Messrs. Benedict and Abbot suggest 885 OPC Ex. 8 (Benedict Cross Rebuttal) at 9. 886 Application of Entergy Gulf States, Inc.for Approval ofIts Transition to Competition Plan and the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705, Second Order on Rehearing at 98 (FoF 224)(0ct. 13, 1998). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE266 PUC DOCKET NO. 39896 allocating MFF relative to each class's inside-city kWh sales with the same MFF per unit cost (i.e., 0.1965¢ per kWh) for all customer classes. 887 Mr. Benedict noted that this allocation method is based on Commission precedent, as indicated in the recent CenterPoint rate case, Docket No. 38339: CenterPoint' s allocation of municipal franchise fees to the customer classes based upon in-city kilowatt-hour (kWh) sales and collection of the fees from all customers within the customer class is reasonable and consistent with Commission precedent. 888 Mr. Benedict also noted that allocating on the basis of in-city kWh sales is consistent with PURA § 33.008(b). 889 Commission Staff supports Mr. Benedict's analysis. Staff points out that PURA§ 33 .008(b ), which authorizes the collection of municipal franchise fees, states that "[t]he compensation a municipality may collect from each electric utility ... shall be equal to the charge per kilowatt hour . . . times the number of kilowatt hours delivered within the municipalities boundaries. " 890 According to Staff, PURA § 33.008(b) plainly links the amount of municipal franchise fees to each class's in-city kWh sales. Moreover, the Commission has an established policy of allocating municipal franchise fees based on in-city kWh sales. 891 According to Staff, the Commission should reaffirm 887 See OPC Ex. 7 (Benedict Cross Rebuttal) at 4-5; Staff Ex. 7 (Abbott Direct) at 22; TIEC Ex. 3 (Pollock Cross Rebuttal) at 34. 888 OPC Ex. 6 (Benedict Direct) at Ex. NAB-1, Application of CenterPoint Electric Delivery Company, UC, for Authority to Change Rates, Docket No. 38339, Order on Rehearing at 34, (FoF 179) (June 23, 2011). 889 OPC Ex. 7 (Benedict Cross Rebuttal) at 5. 890 PURA§ 33.008(b)(emphasis added). 891 Application of TXU Electric Company for Approval of Unbundled Cost ofService Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22350, Order at FoF 156 (Oct. 4, 2001 ). The Commission reached an identical conclusion in Application ofReliant Energy HL&P for Approval of Unbundled Cost of Service Rate Pursuant to PURA 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22355, Order at FoF 222A (Oct. 4, 2001). More recently, Application of CenterPoint Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 38339, Order on Rehearing at FoF 179 (June 23, 2011) (stating that "CenterPoint's allocation of municipal franchise fees to the customer classes based upon in-city kilowatt-hour (kWh) sales and collection of the fees from all customers within the customer class is reasonable and consistent with Commission precedent."). Staff notes in their initial brief that the Commission has further indicated that this allocation should be conducted without any adjustment for differences in the rates charged by individual municipalities within a utility's service territory. Application ofAEP Texas Central Company for Authority to Change Rates, Docket SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE267 PUC DOCKET NO. 39896 this precedent in this case by allocating ETI' s MFF to each customer class on the basis of in-city kWh sales. TIEC witness Pollock disagrees with OPC's and Staffs proposed allocation method, although Mr. Pollock stated their proposal was better than ETI' s proposed allocation. He believes OPC' s and Staff's proposal fails to recognize the different MFF rates charged by cities. Because cities that have a preponderance of industrial sales generally charge lower MFF rates, this proposal would require LIPS customers to pay 0.1965¢ per kWh, which is more than the weighted average MFF cost to the LIPS class of 0.1612¢ per kWh. Thus, Mr. Pollock argues that this would require LIPS customers to subsidize other customer classes and would not be consistent with cost causation. Mr. Pollock thought his proposal to allocate MFF by city by class resulted in each customer class paying only the MFF expenses actually incurred. 892 The AUs find OPC's and Staffs proposed allocation methodology best comports with PURA§ 33.008 and Commission precedent. As noted by Mr. Benedict, PURA was amended after the Commission's decision in Docket No. 16705, which allocated MFF on the basis of rate schedule revenue. PURA§ 33.008 expressly calls for a kWh basis for allocation and this is confirmed in the cases litigated since Docket No. 16705, which were cited by Commission Staff. Accordingly, the AU recommend that MFF be allocated on the basis of in-city kWh sales, without an adjustment for the MFF rate in the municipality in which a given kWh sale occurred. (b) MFF Collection All parties except TIEC recommend that the Commission approve ETI' s proposed allocation of franchise fee rentals to all customers. Cities witness Mr. Brazell testified that franchise fees are in the nature of a rental, not a tax, and like all rental charges ETI incurs, the expense should be spread among all customers. He stated that MFF charges have always been collected from all customers, No. 33309, Order on Rehearing at FoF 150 (Mar. 4, 2008) (stating in connection with a proposed municipal franchise fee expense rider that "[h]aving different rates in each municipality in TCC's service territory is contrary to the Commission's desire for uniform, simple rates"). 892 TIEC Ex. 3 (Pollock Cross Rebuttal) at 8, 33-35. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE268 PUC DOCKET NO. 39896 whether or not they take service within the corporate limits, except for the limited incremental franchise fees specifically addressed by PURA § 39.456. Mr. Brazell explained that electrical facilities within ETI's system are physically interconnected and electrically synchronized. The facilities located within a city's boundaries are not isolated physically or electrically from the facilities outside the city limits. Rather, they are tied to one another and function as a single integrated system, and ETI' s facilities inside each city benefit all customers in ETI' s service area, whether or not those customers are within the city. Therefore, Mr. Brazell recommended that the Commission approve ETI's request to recover MFF in base rates from all customers. 893 Mr. Benedict holds the same opinion. He stated that the Commission's policy to collect MFF from all customers within a customer class is also consistent with the concept that MFF are system costs that are rightly paid by all customers taking service from the system. He explained that MFF are paid by a utility to municipalities for use of the municipalities' rights-of-way. Because these rights-of-way are necessary to operate an integrated electric delivery system from which all customers benefit, regardless of geographic location, Mr. Benedict stated that MFF should be collected uniformly from all customers within a given rate class. He stressed that the Commission agreed with this reasoning in Docket No. 16705, where the Commission concluded: Current cost of services studies are not based on geographical differences. Classes are not divided based on geography, and industrial sites are not self-sufficient islands. The use of city streets and property enables [EGSI] to have an integrated utility system from which all ratepayers benefit. 894 Mr. Pollock objected to the proposals by Mr. Brazell and Mr. Abbott. He stated that Mr. Brazell' s recommendation to adopt ETI' s proposed MFF allocation should be rejected because there is no evidence that outside city customers benefit from ETI' s use of city streets and rights-of- way or that the benefits are evenly distributed between inside and outside city customers. Further, according to Mr. Pollock, the standard used in class cost-of-service studies is cost causation, not 893 Cities Ex. 1 (Brazell Direct) at 28-32. 894 OPC Ex. 6 (Benedict Direct) at Ex. NAB-2, Docket No. 16705, Second Order on Rehearing at 98, (FoF 224). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE269 PUC DOCKET NO. 39896 benefits, and he believes allocating MFF based on outside city usage is contrary to cost causation principles. 895 The AU s recommend adoption of ETI' s proposal to collect costs from all customers taking service from the system. The AUs find persuasive the fact that MFF is compensation for the use of municipalities rights-of-way, which is used to operate an integrated electric delivery system from which all customers benefit. 2. Miscellaneous Gross Receipts Taxes Miscellaneous gross receipts taxes (MGRT) are state taxes imposed on each utility company's taxable gross receipts derived from sales in an incorporated city or town having a population of more than 1,000. Like MFF, these taxes are levied only on sales within the cities. ETI proposes to allocate MGRT to all retail customer classes based on customer class revenues relative to total revenues. 896 TIEC objects to ETI's allocation of MGRT based on class revenues for the same reasons stated for ETI' s allocation of MFF. It argues that these costs should be allocated and charged to customers within the municipalities to which the MGRT applied. The allocation of MGRT is similar to the allocation ofMFF and should be similarly applied. For the reasons set out above and to ensure consistent treatment, the AU s do not recommend the direct method of allocation suggested by TIEC. Rather, these costs should be allocated to the rate classes according to ETI' s cost of service study. 895 TIEC Ex. 3 (Pollock Cross Rebuttal) at 7, 32-33. 896 ETI Ex. 3, Schedule P-13 at 10, line 34. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE270 PUC DOCKET NO. 39896 3. Capacity-Related Production Costs (a) Allocation Methodology ETI proposes to allocate capacity-related production and transmission costs to the retail classes on the basis of A&E 4CP. As noted by TIEC and Commission Staff, this allocation methodology is consistent with the method ETI used in Docket No. 16705, its last contested rate proceeding: Finding of Fact No. 221. The continued use of the A&E 4CP allocator is the most reasonable methodology for allocating production and transmission plant among classes. The A&E 4CP allocator sufficiently recognizes customer demand and energy requirements and assigns cost responsibility to peak and off-peak users. It best recognizes the contribution of both peak demand and the pattern of capacity use through the year. Finding of Fact No. 222. The A&E 4CP method is also preferable because it is devoid of any double counting problem. 897 ETI witness Ms. Talkington explained that the A&E 4CP allocation is appropriate because it is a method that reasonably reflects the mix of the Company's customers, their respective electrical load characteristics, and the relative costs incurred to serve such loads. She testified that the A&E 4CP method provides a reasonable balance between the two primary costing concerns: contribution to the system peak and energy requirements. While the contribution made to the system peak is inherently recognized with the use of the average four coincident peaks, energy is also recognized by reflecting the average demands. 898 OPC witness Benedict proposed the use of the average and single coincident peak (A&P) method to allocated production (and transmission costs, which are discussed in the section below) 897 Docket No. 16705, Second Order on Rehearing at 97, FoF 221 and 222 (Oct. 14, 1998). 898 ETI Ex. 22 (Talkington Direct) at 5. As noted previously, A&E 4CP is developed by adding each rate class's average demand for the test year (the "average" component representing the rate class's average energy consumption), weighted by the ETI system load factor, to each rate class's amount of average coincident peak demand for the months of June through September in excess of its average demand, weighted by one minus the ETI system load factor. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE271 PUC DOCKET NO. 39896 among retail classes. As noted in the discussion concerning jurisdictional allocation, A&E 4CP is a variant of the A&E allocator. Mr. Benedict believes that A&E 4CP fails to properly assign cost responsibility to both peak and off-peak usage. 899 Instead, he found that the A&E 4CP allocator results in the same factors reached by the 4CP method, which means that A&E 4CP assigns cost responsibility only to peak demand and not to off-peak demand. He believes that the A&P methodology is the proper plant allocator because it takes into account both peak usage and off-peak usage patterns. 900 Mr. Benedict's methodology and recommendation was disputed by Kroger witness Higgins. He indicated that the A&E method does not converge to a CP result. Rather, the A&E method addresses a fundamentally important question in production cost allocation-once capacity needed to serve the average demand on the system is accounted for, how does the regulator fairly assign the responsibility for the additional or excess capacity that is needed to meet the various capacity requirements (placed on the system by each customer class). Mr. Higgins concluded that the A&E method makes an objective and reasonable allocation. However, he did not advocate changing ETI' s use of A&E 4CP. 901 Mr. Higgins explained that: [T]he Average and Excess demand method begins by allocating a portion of costs on the basis of average demand-or energy. The remaining (or "excess") capacity needs of the system are then allocated to classes based on peak usage--class NCP in the case of the "standard" approach, 4 CP in the case of the A&E/4CP method. In contrast, the A&P method proposed by Mr. Benedict, which is classified by the NARUC Manual as a "Judgmental Energy Weighting" approach, incorporates a subjective determination that includes the full value of average demand both in the "average" component of the A&P calculation as well as in the peak component of that calculation. 902 899 Mr. Benedict performed a mathematical proof that he believed demonstrated that the A&E 4CP allocator is nearly identical to the 4CP allocator. OPC Ex. 6 (Benedict Direct) at 21-22. 900 Id. 901 Kroger Ex. 2 (Higgins Cross Rebuttal) at 4-5. 902 Id. at 6 (emphasis in originial). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE272 PUC DOCKET NO. 39896 TIEC witness Pollock also disputed Mr. Benedict's proposed methodology, stating that A&P does not reflect cost causation and is not reasonable for ETI. He believes that Mr. Benedict's support of the A&P method is based on an oversimplification of the planning process. He also noted that A&E is recognized in the NARUC Electric Utility Cost Allocation Manual and has been repeatedly used by the Commission. 903 The following calculations performed by Messrs. Benedict and Higgins demonstrate the different results stemming from the allocation methodologies: 904 ETI OPC Kroger Pro12.osed Recommended Standard Alternative Rate Class A&E/4CP(%) A&P(%) A&E 12CP Residential 47.4494 40.1181 48.4013 43.4768 Small General Service 2.0990 2.0595 2.7209 2.0169 General Service 18.0259 19.4933 18.5183 18.6122 Large General Service 7.0794 8.3822 6.6558 7.4339 Lg. Indust. Power Serv. 20.4401 25.5485 20.2122 22.9417 Total Lighting 0.2900 0.2768 0.4042 0.1394 Total Texas Retail 95.3838 95.8784 96.9127 94.6208 Total Wholesale and 4.6162 4.1216 3.0873 5.3792 Wheeling Total Company 100.0000 100.0000 100.0000 100.0000 The AUs recommend the use of A&E 4CP to allocate capacity-related production costs, as proposed by ETI. The weight of the evidence as well as Commission precedent does not support the methodology proposed by Mr. Benedict. A&E 4CP was approved for the Company in Docket No. 16705, and the extensive testimonies (which included calculations and graphs) of Messrs. Higgins and Pollock indicate that, not only is the methodology frequently adopted by the Commission, it is also a standard and reasonable methodology. As noted by ETI, it reasonably reflects the mix of the Company's customers and their respective load characteristics and the relative 903 TIEC Ex. 3 (Pollock Cross Rebuttal) at 12-14, citing the NARUC Electric Utility Cost Allocation Manual, January 1992. 904 OPC Ex. 6 (Benedict Direct) at 25; Kroger Ex. 2 (Higgins Cross Rebuttal) at 5. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE273 PUC DOCKET NO. 39896 costs incurred to serve such loads. It recognizes the contribution of both peak demand and the pattern of capacity use throughout the year. 905 It also recognizes that ETI, like all Texas utilities, is a summer peaking utility. The AU s recommend that ETI' s allocation of capacity production costs be adopted. (b) Reserve Equalization Payments A subset of the Company's requested capacity-related production costs relate to reserve equalization payments made by the Company pursuant to the Entergy System Agreement (Service Schedule MSS-1 ). The System Agreement, which is approved by the FERC, prescribes a method by which each Entergy Operating Company's share of Entergy system reserves are calculated. ETI, as one of the Operating Companies, is responsible to provide the system with its allocated share of system reserves. Some Entergy Operating Companies own less than their share of system reserves and are considered "short" with respect to generation capability. Companies that own more than their share are considered "long" companies. Short companies make payments to long companies pursuant to the terms of the System Agreement. Because ETI is a short company, it makes reserve 906 equalization payments which are included in the cost of service. ETI allocates MSS-1 payments using A&E 4CP. Mr. Benedict argues that this allocation method is not consistent with the way costs are incurred, as ETI does not make MSS-1 payments on the basis of A&E 4CP. According to Mr. Benedict, ETI incurs costs by being short with respect to system reserves-the payment is simply the number of MW by which it is short, multiplied by a $/MW rate as determined by a contract formula. The degree to which ETI is short is determined by comparing its generation capability to its allocated share of system reserves. Total system reserves are allocated to the other Operating Companies on the basis of the Responsibility Ratio. Thus, as 905 See Docket No. 16705, Second Order on Rehearing at FoF 221 (Sept. 4, 1998). 906 OPC Exhibit No. 6 (Benedict Direct) at 29-30. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE274 PUC DOCKET NO. 39896 determined by the Responsibility Ratio, ETI's share of system reserves relative to its generating capability is what causes ETI to make MSS-1 Reserve Equalization payments. 907 Mr. Benedict concluded that, because Reserve Equalization payments are incurred on the basis of ETI' s Responsibility Ratio, which is a rolling 12CP allocator, the payments should be allocated to ETI' s rate classes on a similar basis. As a result, he recommended that Reserve Equalization payments be allocated on the basis of 12CP.908 According to OPC, Mr. Benedict's proposal for allocating MSS-1 payments has been criticized because 12CP measures class demands at ETI's peak monthly demands whereas the Responsibility Ratio is measured at the Entergy system's peak monthly demands. OPC agrees that 12CP uses peak hours that may differ from those used to compute the Responsibility Ratio, but contends that the Company fails to mention that the A&E 4CP method it uses to allocate MSS-1 payments is also subject to the same critique. When choosing between the 12CP allocator and the A&E 4CP allocator for the purpose of allocating reserve equalization payments, OPC believes 12CP is more desirable. ETI' s contributions to the Entergy system's peaks in all 12 months, not just the four summer months, determine ETI' s share of Entergy system reserves. ETI' s share of system reserves, relative to its generation capability, is what causes reserve equalization payments to the other Entergy Operating Companies. Moving to a 12CP allocation for MSS-1 payments aligns cost allocation more closely with cost causation. TIEC witness Pollock explained that the Entergy System Agreement is regulated by the FERC, which does not control the rate design policy applicable to Texas retail customers under Commission jurisdiction. He views the System Agreement as an accounting mechanism to equalize the benefits and costs associated with interconnected operation and joint planning. In his opinion, it is not relevant to determining which production capacity allocation method best reflects cost causation for Texas retail customer. According to Mr. Pollock, the MSS-1 payments are no different in concept from the costs associated with ETI' s high-voltage transmission lines, which are allocated 901 Id. 908 Id. at 31. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE275 PUC DOCKET NO. 39896 on an A&E 4CP basis. He further indicated that the 12CP method ignores the reality the ETI is a predominantly summer peaking utility. 909 The ALls do not find sufficient support to allocate the reserve equalization payments differently than other capacity-related production costs. For the same reasons noted in the section above, the AlJ s find the weight of the evidence supports allocation using A&E 4CP. While 12CP is a reasonable methodology for jurisdictional separation between retail and wholesale entities, the evidence does not support this methodology for allocation of reserve equalization payments. 4. Transmission Costs As noted above, ETI also allocates transmission costs using the A&E 4CP methodology. Again, TIEC and Staff cite to the Commission's decision in Docket No. 16705, which adopted the A&E 4CP approach for both production and transmission costs. OPC witness Benedict, however, proposes allocating transmission plant using A&E methodology that he proposed for the allocation 910 of production plant. TIEC argues that methodologies similar to Mr. Benedict's proposal have been repeatedly rejected by the Commission, and the A&E 4CP methodology has been repeatedly approved. TIEC suggests that Mr. Benedict offers no rationale for a different result for transmission costs. According to TIEC, the rationale that he offers for using the A&P method for production costs-the potential trade-off between capital costs and fuel costs-is entirely absent with respect to transmission plant. Mr. Benedict does not even assert that such trade-offs exist. Rather, the only basis he offers for using the average and peak methodology is his assertion that the A&E 4CP allocator "mathematically reduces to a 4CP allocator."911 TIEC points out that the Commission, by rule, has adopted the 4CP method for the allocation of transmission plant within ERCOT. 912 909 TIEC Ex. 3 (Pollock Cross Rebuttal) at 27-29. 910 OPC Ex. 6 (Benedict Direct) at 26-28. 911 TIEC Initial Brief at 68, citing OPC Ex. 6 (Benedict Direct) at 27. 912 P.U.C. SUBST. R. 25.192 specifically provides that transmission costs are allocated based on the SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE276 PUC DOCKET NO. 39896 ETI witness Talkington indicated the same reasons and rationale for using the A&E 4CP methodology to allocate transmission costs as she noted for capacity-related production costs. 913 Kroger witness Higgins also disputed the use of A&E 4CP for allocation of transmission costs for the same reasons noted above concerning production cost allocation. Moreover, he compared the different allocation factors-specifically, ETl's proposed A&E 4CP, the A&E, and Mr. Benedict's recommended A&P. His calculations indicated that A&E 4CP and the A&E produce 914 similar results, while A&P radically departs from ETI's proposed allocations. The AUs do not find sufficient or persuasive evidence to change ETI's proposed methodology for allocation of transmission costs. A&E 4CP is a well-accepted method for allocating such costs, which the Commission has repeatedly adopted. The AUs recommend the use of the A&E 4CP to allocate ETI' s transmission costs. C. Revenue Allocation Wal-Mart, Kroger, TIEC, and Commission Staff advocate that the rates be set on the basis of the utility's costs of service. These parties recommends the adoption of ETis proposed base rate revenue allocation, recovering from each class 100 percent of it respective Test-Year base rate costs per the revenue requirement ultimately adopted. TIEC witness Pollock testified that revenue allocation is the process of determining how any base revenue change approved by the Commission should be spread to each customer class served by the utility. ETI proposed an overall increase in non-fuel revenues of 17 .53 percent, but the increase is not spread proportionally to all the classes.915 Rather, ETI proposed class revenue requirements "coincident peak demand for the months of June, July, August, and September (4CP) .... " 913 ETI Ex. 67 (Talkington Rebuttal) at 8-9. 914 Kroger Ex. 2 (Higgins Cross Rebuttal) at 5-6. 915 ETI's revenue requirement does not include the costs associated with its requested REC Rider. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE277 PUC DOCKET NO. 39896 that are closely aligned with the Company's proposed cost of service. Set out below is the impact of ETI's proposed base rate increase for each class: 916 Class Change in Base Revenues Residential 25.10% Small General Service 1.82% General Service 5.54% Large General Service 19.06% Large Industrial Power Service 11.17% Lighting Service 29 .36% System Average 17.53% The contested issue concerns whether rates should be set at cost, and any approved change in base rate revenues should reflect the actual cost of providing service, or whether any rate increase should be phased in for certain classes (notably Residential and Lighting classes) to reduce the impact (rate shock) 1. Argument for Moving Rates to Cost ETI and the parties in support of ETI' s class revenue allocation contend it is appropriate to set rates at each class' cost of service as ETI has proposed in order to avoid continuing inappropriate and inequitable cost shifting between customer classes. TIEC witness Mr. Pollock testified that cost-based rates send the proper price signals to customers. He noted other reasons for using cost-of- service principles: equity, engineering efficiency (cost-minimization), stability, and conservation. If rates are not based on cost, then some customers subsidize part of the cost of providing service to other customers. Moreover, he suggested that by providing balanced price signals, cost-based rates 916 See Kroger Ex. 1 (Higgins Direct) at 5-6; see also Cities Ex. 6 (Nalepa Dire.ct) at 34.  -------- SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE278 PUC DOCKET NO. 39896 encourage conservation and may prevent waste or inefficient use. If rates are not based on a class 917 cost-of-service study, then consumption choices can be distorted. Mr. Pollock developed a class revenue allocation based on his proposed jurisdictional and class cost-of-service studies. If these recommendations are adopted, his class revenue allocation produced the following results: Rate Class Present Non-Fuel Proposed Base Revenues Revenue Increases Percent Increase Service Residential $379,382,000 $80,390,000 21.2% Small General $26,430,000 $283,000 1.1% General $159,768,000 $9,797,000 6.1% Large General $49,380,000 $8,714,000 17.6% Large Indus. Power $104,308,000 $9,862,000 9.5% Lighting $10,813,000 $2,143,000 19.8% Total $730,080,000 $111,189,000 15.2% As discussed below, Mr. Pollock also recommended lower rates for Schedules SMS and AFC, which would reduce ETI' s revenues by about $2 million. To offset this loss, he testified that revenues would need to be increased for other classes to achieve the total increase requested by ETI. These changes would produce the following results: 918 Rate Class Service Present Non-Fuel Proposed Base Percent Increase Revenues Revenue Increases Residential $379,382,000 $81,500,000 21.5% Small General $26,430,000 $340,000 1.3% General $159,768,000 $10,205,000 6.4% Large General $49,380,000 $8,860,000 17.9% Large Indus. Power $104,308,000 $10,153,000 9.7% 917 TIEC Ex. l (Pollock Direct) at 63-65. 918 Id. at 63-67 and Exs. JP-12 and JP-13. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE279 PUC DOCKET NO. 39896 Rate Class Service Present Non-Fuel Proposed Base Percent Increase Revenues Revenue Increases Lighting $10,813,000 $2,160,000 20.0% Total $730,080,000 $113,218,000 15.5% SMSIAFC Impacts $13,816,000 ($2,029,000) -14.7% Total Sales $743,896,000 111,189,000 14.9% If the Commission disallows other elements of ETI' s rate request, Mr. Pollock testified that class revenue allocation should be reduced in accordance with how such disallowed costs were allocated to each rate class. 919 Mr. Pollock's tables provide examples of the impact on each class of customers when the Commission makes final decisions concerning the Company's proposed rate design and the final revenue requirement. Staff witness Abbott testified that the Commission ordinarily sets rates for each customer class to recover the costs incurred by the utility to serve that class. In this case, ETI' s proposed revenues for all customer classes result in base revenues that are close to the cost of service allocated costs. No single customer class' proposed revenue requirement differs from ETI' s calculated cost to serve that class by more than 3 percent. Staff acknowledges that certain classes face proportionally larger rate increases to bring them closer to unity, where revenue recovery is based on actual cost of service. However, Staff agrees with Mr. Pollock that setting each customer class at their cost of service avoids inflating rates for some customer classes and subsidizing the usage of others. Staff believes that recovering from each class its respective base rate cost is equitable and provides appropriate pricing signals to facilitate the most efficient use of resources in the provision and consumption of electricity. Staff also argues that the Commission has approved such class cost of service allocation in recent rate cases. 920 919 Id. at 67. 920 Staff cites Application of CenterPoint Electric Delivery Company, UC for Authority to Change Rates, Docket No. 28339, Order at FoF 175 (May 12, 2011) and Docket No. 16705, Second Order on Rehearing at SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE280 PUC DOCKET NO. 39896 Wal-Mart and Kroger concur with Staff and TIEC. 2. Argument for Gradualism Cities witness Karl Nalepa pointed out that, under ETI' s proposed rates, the Residential and Lighting customer classes receive the highest rate increases while the Small General Service, General Service, and Large Industrial Power Service classes receive below system average rate increases of 1.62 percent, 4.81 percent, and 10.77 percent, respectively. However, he examined Test Year customer quantities, energy and loads by customer class for each of ETI' s last three cases, and he concluded that residential and lighting customers are not imposing an undue cost burden on the system. Instead, other classes are growing at a faster rate, causing system costs to increase. Moreover, Mr. Nalepa testified that a number of events are occurring with the Entergy system that will have significant impact on costs, including: Entergy' s efforts to join MISO; plans by EAi and EMI to leave the Entergy System Agreement; and the possible divestiture of the transmission system by all Entergy Operating Companies. Given these uncertainties, Mr. Nalepa proposed that any rate increase or decrease be spread proportionately across the system classes. Then, once Entergy and ETI address the proposed system cost changes, a reasonable class cost allocation study can be presented. 921 State Agencies do not take a position on overall class revenue allocation but request that ETI' s proposed rate increase for the Lighting class be moderated. ETI proposes to set base rate revenues for the Lighting class based on the class cost allocation study, without any adjustment, which would result in a 20.38 percent increase to the Lighting class, when the entire ETI system would receive a 15.32 percent increase. Thus, under ETI's proposal, this class would receive a percentage increase about 1.33 times the system average. Ms. Pevoto contended that that this increase would be excessive and would create significant rate shock to the class. Because the FoF 245 (Sept. 4, 1998). TIEC witness Pollock also testified that Commission precedent supports allocation of costs based on the cost of service study. He also cited to the CenterPoint case and to Application ofAEP Texas Central for Authority to Change Rates, Docket No. 28840, Order at 50 (Aug. 15, 2005). TIEC Ex. l (Pollock Direct) at 65. 921 Cities Ex. 6 (Nalepa Direct) at 34-37. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE281 PUC DOCKET NO. 39896 services of the Lighting class provides benefits all customers on the system, Ms .. Pevoto believes it would be reasonable to mitigate the rate shock so that lighting customers can afford to continue their lighting service. Otherwise, she suggested, some lighting customers may reduce lighting services or refrain from ordering additional lights. This, in tum, would adversely affect the benefits that lighting service provides to the public. 922 Ms. Pevoto also pointed out that in 2009, the Commission adopted a rate moderation proposal for a similar rate class served by another utility. In that case, the Commission recognized that the Lighting class was unique in the combination of the public good it performs and in its demand characteristics. 923 To mitigate the rate shock on the lighting customers in the present case, Ms. Pevoto recommended a cap on any base rate increase that would be equal to the smaller of: (1) the lighting class percentage rate increase resulting from the PUC-approved cost of service allocation study, or (2) the allowed system percentage rate increase. If the percentage rate increase is smaller than the allowed system percentage rate increase, then no mitigation adjustment would be necessary. However, if the PUC-approved cost of service allocation results in a percentage base rate increase for the lighting class that is greater than the allowed system percentage increase, then she urged that a mitigation reduction should occur. She also proposed that any mitigation reduction for the lighting class should be spread to other remaining classes, based on each class' cost of service. 924 ETI argues that the State Agencies are proposing the continuation of a significant subsidy by other classes. The Company notes that its allocation of costs to the Lighting class is based on the revenue requirement developed for that class. ETI acknowledges that its proposed increase for the Lighting class is 20.38 percent greater than the system average increase, but it is less than the Residential class's proposed increase of21.64 percent. ETI witness Ms. Talkington testified that the 922 State Agencies Ex. 2 (Pevoto Direct) at 12-13. 923 Application of Oncor Electric Delivery Company for Authority to Change Rates, Docket No. 35717, Order on Rehearing at 32 (Nov. 30, 2009). 924 State Agencies Ex. 2 (Pevoto Direct) at 15-16. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE282 PUC DOCKET NO. 39896 Company does not support any subsidies between rate classes. She testified that previous rate cases with subsidies for the Lighting class have pushed the class farther away from cost. 925 OPC argues that cost of service should not be the sole factor in setting rates and that gradualism should be used in appropriate circumstances. OPC witness Benedict disagreed with Mr. Pollock's (and Staff's) citation to the CenterPoint andAEPTCC rate cases to reject the concept of gradualism because both CenterPoint and TCC are unbundled transmission and distribution (T&D) utilities whose charges had a small impact on retail customers' total bill. He noted that the number runs for TCC and CenterPoint showed retail revenue increases of only 0.14 percent and 1.30 percent, respectively, with some classes receiving rate decreases. 926 Mr. Benedict cited the following language by the Commission in its Order for the TCC case: The Commission declines to adopt gradualism in this case. This proceeding develops the T&D rates, as opposed to the broader rates developed for a fully integrated utility. As the T&D rates are only a subset of the total rates paid by customers, changes to the T&D rates would not have as large an impact as they would if the broader rates for a customer class were changed by the same percentage.... 927 In Mr. Benedict's opinion, gradualism should be employed when setting rates for ETI because ETI is an integrated utility and has proposed a large rate increase. 928 Mr. Benedict also emphasized the imprecise nature of a cost of service study. He noted that ETI's cost of service study had 47 allocation factors and, even at the summary level, 22 expense categories and 24 rate base categories. 929 Thus, he stated, there are a host of decisions made by the cost of service analyst which, in combination with the various account entries, yield a class' reported cost of service. Mr. Benedict also pointed to disagreement among qualified experts on the "correct" 925 ETI Ex. 67 (Talkington Rebuttal) at 18-19. 926 OPC Ex. 8 (Benedict Cross Rebuttal) 11-12; Ex. NAB-4, Docket No. 28840, TCC Number Run (July 21, 2005); and Ex. NAB-5, Docket No. 38339, Revised Number Running Schedules (Feb. 18, 2011). 927 Id. citing Docket No. 28840, Order at 23 (Aug. 15, 2005). 928 OPC Ex. 8 (Benedict Cross Rebuttal) at 9-14. 929 Allocation factors are provided in Schedule P-7 .1; Expenses are summarized in Schedule P-7.4; Rate Base is summarized in Schedule P-7.5. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE283 PUC DOCKET NO. 39896 allocation for certain classes of costs. 930 In addition to these allocation questions, Mr. Benedict stated that any disallowances made to ETI's requested costs will have asymmetric effects on class cost of service depending on how the costs were allocated. Thus, while the cost of service study is 931 an important element of ratemaking, Mr. Benedict stressed that it is not the only consideration. Due to the wide variation of rate increases obtained from ETI' s cost of service study, Mr. Benedict thought that rate moderation (gradualism) would be appropriate. However, he added, until decisions are made regarding the cost disallowances and allocation modifications proposed by the parties, it is unclear which rate classes should be granted rate moderation and the degree to which rate moderation is needed. Mr. Benedict said that the system average rate increase should be used as a benchmark for rate moderation, but not assigned uniformly to all classes as Mr. Nalepa proposed or to just one class as Ms. Pevoto suggested. Instead, he believed it would be reasonable to establish a floor and a ceiling for the increases in revenue from each class, such that a class' individual percentage increase in revenue requirement is within a defined range of the system's average revenue increase. Therefore, Mr. Benedict recommended that any rate increase for a particular class be restricted to a range of 0.75 to 1.25 times the system's average increase. This would result in rate increases up to 25 percent lower or 25 percent higher than the average rate increase for the system as a whole. Based on a system average increase of 17.53 percent, individual class increases would range from 13.15 percent to 21.91 percent under Mr. Benedict's proposal. 932 3. ALJs' Recommendation The parties presented persuasive argument on both sides of the issue. Clearly, in any rate case, movement toward unity-setting rates to cost-is appropriate when such movement does not result in rate shock to a particular class or classes. If rate shock is likely, Commission precedent 930 He noted, for example, that his direct testimony and Mr. Nalepa' s direct testimony proposed a different allocation methodology for production-related capacity costs, transmission costs, and certain System Agreement costs. Mr. Pollock proposed a different allocation method for municipal franchise fees and local gross receipts taxes. Mr. Abbott recommended different allocation methods for municipal franchise fees and other franchise taxes. 931 OPC Ex. 8 (Benedict Cross Rebuttal) at 14-17. 932 OPC Ex. 8 (Benedict Cross Rebuttal) at 17-19. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE284 PUC DOCKET NO. 39896 supports the use of gradualism. These policies apply to both a fully integrated utility, as well as a T&D. The salient issue is whether the utility's proposed increase is so out of proportion or harsh to a particular class that some form of gradualism should be applied. In this rate case, the preponderance of the evidence does not support the use of gradualism, even for the Lighting class. While that class may receive an increase almost 1.33 times the system average increase, Commission precedent indicated an appropriate ceiling of 1.5 or even 1.75 times the system average is appropriate. 933 As to applying OPC's proposed floor and ceiling approach, this method was introduced in cross-rebuttal with no calculations depicting the impact on each class. The A1J s do not recommend its adoption because it fails to offer significant movement towards class responsibility for cost of service. The A1J s do not recommend Mr. Nalepa' s suggestion to impose any revenue change on an equal percent basis because it offers no movement towards unity. Accordingly, the A1J s concur with the parties supporting ETI that revenue allocation in this case should be based on each class's cost of service and consistent with the AU s' recommendations in the PFD that impact revenue allocation. D. Rate Design [Germane to Preliminary Order Issue Nos. 15, 18, and 20] Staff explained that the Commission has traditionally established class costs of service based on the principle of cost causation. Staff believes the Commission has consistently required substantial justification for departing from this principle when setting rates that result in cross-subsidization between customer classes. With respect to intra-class cost causation and rate design, Staff maintains that the considerations are somewhat different. Rather, the Commission has traditionally given more weight to policy considerations other than cost causation in determining intra-class rate design issues because the danger of permanent subsidies within a particular class is relatively low. 934 For instance, Staff witness Abbott testified that customer usage within a class may vary throughout the year. He noted that a low-load-factor customer might become a high-load-factor 933 See Docket No. 28840, Order at 23 (rejecting ALJs' proposed ceiling of 1.75 times the system average). 934 Staff cites to Mr. Abbott's cross-examination at Tr. at 1818 ("Q: And is there a distinction between factors that you would consider such as costs or other factors when you're discussing class allocation as opposed to rate design issues? A: I would say there are different considerations and weights to considerations and the analysis of allocating costs to classes versus the analysis of allocating costs to rates within a class."). SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE285 PUC DOCKET NO. 39896 customer, resulting in a different mix of charges throughout the year. 935 While an individual customer's usage characteristics might frequently change and thereby lessen the impact of cost shifting within a class, Mr. Abbott testified that such customers were unlikely to shift to a different customer class. 936 While subsidies in the customer class allocation context might be permanent, this was not necessarily the case for intra-class rates. Moreover, these shifting usage characteristics make it more difficult to identify cost drivers within a rate class. Staff suggests that consideration be given to policies such as customer impact and energy efficiency. The ALls agree with Stafrs analysis. Mr. Abbott recommended that the Commission apply gradualism-limiting the magnitude of rate changes-to help stabilize customer expectations and reduce risk. 937 ETI witness Talkington also advised caution in response to suggested changes to ETI's proposed rate design, noting that the ultimate impact on a customer's bill is important. 938 However, the ALJ s' rate design recommendations are based on the evidence and argument for each customer class or rate schedule. Thus, the ALJ s' recommendation on the specific rates or charges for the industrial customers will impact all other customer classes but that impact is not known at this time. 1. Lighting and Traffic Signal Schedules Cities witness Dennis W. Goins explained ETI's Lighting and Traffic Signal Schedules. ETI' s principal rate schedule for street lighting customers is Schedule SHL (Street and Highway Lighting Service), while Schedule TSS (Traffic Signal Services) is the principal rate schedule for ETI' s traffic lighting customers that own and maintain their lighting facilities. For Schedule SHL, the rate includes four categories of service (Rate Groups A, C, D, and E). Rate Group A includes ETI' s standard fixture and lamps mounted on existing standard wood poles that ETI installs and maintains. If a customer wants nonstandard lighting facilities (those not provided in Rate Group A), 935 Tr. at 1818. 936 Id. 937 Staff Ex. 7 (Abbott Direct) at 25-26. 938 ETI Ex. 67 (Talkington Rebuttal) at 16. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE286 PUC DOCKET NO. 39896 the customer is assigned to Rate Group C and required to prepay ETI for the incremental cost of the nonstandard facilities. Lighting facilities that are customer-owned and customer-maintained are assigned to Rate Group D, while incidental lighting services (for example, underpass lighting) are assigned to Rate Group E. Customers in Rate Groups A and C pay a fixed monthly charge per lighting fixture, while customers in Rate Groups D and E pay a fixed (and identical) energy charge per kWh. Each customer's monthly bill also includes charges for ETI's fixed fuel factor (Schedule FF) and applicable riders applied to monthly kWh per fixture. Under Schedule TSS, traffic signal customers are subject to a minimum monthly charge ($3.20 proposed) per point of delivery, plus a fixed kWh rate and all applicable rider charges. 939 Cities request that the Commission require ETI to institute a discounted lighting rate for Light Emitting Diode (LED) installations. Mr. Goins testified that the basic structure and pricing provisions of the SHL and TSS rates were designed for lighting fixtures that use older, less energy-efficient bulb technology, and ETI did not conduct any analyses to estimate the cost differential of serving street lighting and traffic signal customers that use energy-efficient LED fixtures. In fact, Dr. Goins noted that the basic structure and pricing provisions of the SHL and TSS rates have been place for years. 940 In Dr. Goins' opinion, adoption of LED lighting rates would help reduce energy consumption in Texas because such rates help offset the high front-end cost of LED lights and encourage municipalities to adopt energy-efficient LED options. In 2010, the Commission approved a street and traffic signal rate for El Paso Electric Company that included separate charges for LED traffic signals. 941 In that case, the fixed monthly rate for LED signals was generally less than one-third the comparable rate for incandescent signals. 939 Cities Ex. 4 (Goins Direct) at 22-23. 940 Id. at 23. 941 Application of El Paso Electric Company to Change Rates, to Reconcile Fuel Costs, to Establish Formula- Based Fuel Factors, and to Establish an Energy Efficiency Cost Recovery Factor, Docket No. 37690 (July 30, 2010). SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE287 PUC DOCKET NO. 39896 Dr. Goins recommended that the Commission require ETI to modify monthly fixed charges in Schedule SHL (Rate Groups A and C) and the monthly minimum charge in Schedule TSS to reflect a 25 percent discount for LED installations. Under his proposal, the discounted Rate Group A fixed charges (if applicable) in Schedule SHL would be applied according to the estimated monthly kWh consumption of the installed LED fixture. In addition, he recommended reducing by 25 percent the Schedule SHL kWh charges applicable to LED customers assigned to Rate Groups D and E to reflect the lower cost of operating and maintaining LED fixtures. And he added that, in the future, ETI should be required to provide detailed information regarding differences in the cost of serving LED and non-LED lighting customers. 942 Dr. Goins also requested that the Commission require ETI to eliminate the service condition applicable to Rate Groups A and C in Schedule SHL that charges a $50 fee for any replacement of a functioning light with a lower-wattage bulb. He stated that this fee actively discourages customers from adopting more energy-efficient lighting technologies (for example, LED devices), and was not supported in ETI's filing. In Dr. Goins' view, this barrier to conservation and efficiency improvements should be eliminated. 943 Staff disagrees with Cities' request that ETI institute a discounted lighting rate for LED installations. Mr. Abbott testified that Cities did not provide empirical cost data to support this request. Without data on which to base an LED installation discount, he recommended that the Commission not require ETI to provide such a discount at this time. However, because of the growing use of LED installations and the potential cost savings to be realized from these installations, Mr. Abbott did recommend that the Commission require ETI to perform a cost study to determine appropriate cost-based rates for LED installations. This cost study could be used to develop LED lighting rates, which Mr. Abbott recommended ETI be required to submit as part of its next base-rate case. 944 942 Cities Ex. 4 (Goins Direct) 22-26. 943 Id. 944 Staff Ex. 7 (Abbott Direct) at 28. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE288 PUC DOCKET NO. 39896 ETI is willing to perform a study to determine the feasibility of implementing LED lighting rates as part of its next base rate case filing. ETI witness Talkington explained that the Company does not currently offer ETI-owned LED lights but may do so in the future. She stated that if a customer wishes to use LED technology, it can install LE fixtures and receive service under Schedule SHL, Rate Groups D and E, or the existing Schedule TSS. 945 Ms. Talkington took issue with Dr. Goins' proposed 25 percent decrease in Schedule SHL (Rate Groups A and C) and Schedule TSS for an LED option because the 25 percent rate reduction was not calculated. Thus, ETI prefers that it propose rates after a cost study. Ms. Talkington also disagreed with Dr. Goins' proposal for a 25 percent decrease in the energy-only options under Schedule SHL, Rate Groups D and E or Schedule TSS for customer-owned lights. She believes that a customer will have the benefit of more efficient LED lights by the reduction in energy consumed. 946 The AUs find persuasive Dr. Goins' testimony that: (1) the cost of street and traffic lighting services can be significant for many cities and towns; (2) government agencies face increasing pressure to control budgets and energy-efficient lighting is a good option; (3) LED fixtures use significantly less energy than incandescent and most other light options, last longer, and may require less maintenance; and (4) LED lighting rates would encourage municipalities to adopt energy-efficient LED options and help offset the high front-end cost of LED lights. 947 However, the AUs concur with ETI and Staff that ETI should be directed to perform a LED lighting cost study before extensive changes are made to its lighting rates. The AU s further recommend that ETI conduct this study before filing its next rate case and provide the results of any completed study to Cities and interested parties as soon as practicable but no later than the filing of its next rate case, as requested by Cities. Further, the AUs recommend that the study include detailed information regarding differences in the cost of serving LED and non-LED lighting customers, if ETI has LED lighting customers taking service at the time it conducts its study. Finally, the AUs note that ETI 945 ETI Ex. 67 (Talkington Rebuttal) at 17. 946 Id. at 17-18. 947 Cities Ex. 4 (Goins Direct) at 24-25. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE289 PUC DOCKET NO. 39896 did not dispute Dr. Goins' suggestion to eliminate the service condition for Rate Groups A and C in Schedule SHL that charges a $50 fee for any replacement of a functioning light with a lower-wattage bulb. As noted by Dr. Goins, this fee discourages customers from adopting more energy-efficient lighting (such as LED devises). The Al.Js concur and recommend that ETI modify the applicable tariffs to eliminate this fee for any replacement of a functioning light with a lower-wattage bulb. 2. Demand Ratchet Staff witness Abbott testified that a demand ratchet is a provision in a utility's tariff that allows it to bill a customer based upon on the greater of either demand by that customer in the current month, or some fixed percentage of the customer's demand occurring during previous months. The Commission approved a settlement in Docket No. 37744, ETI's last base rate case, in which, among other things, ETI agreed to eliminate all life-of-contract demand ratchets from its tariffs for new customers with the implementation of rates. ETI further agreed that, in its next rate case, it would eliminate the life-of-contract ratchet for existing customers. 948 The Docket No. 37744 stipulation stated: Life-of-Contract Demand Ratchet. The Signatories agree that the life-of-contract demand ratchet provision in Rate Schedules Large fudustrial Power Service [LIPS], Large fudustrial Power Service-Time of Day [LIPS-TOD], General Service [GS], General Service-Time of Day [GS-TOD], Large General Service [LGS ], and Large General Service-Time of Day [LGS-TOD] shall be excluded from the rate schedules in ETI's next rate case. The Signatories further stipulate that the foregoing rate schedules will be revised so that the life-of-contract demand ratchet provision shall not be applicable to new customers and, for existing customers, shall not exceed the level in effect on August 15, 2010. 949 ETI then filed compliance tariffs in Docket No. 37744, which implemented the first part of the settlement by excluding new customers from its proposed life-of-contract demand ratchet. The 948 Staff Ex. 7 (Abbott Direct) at 16; Application of Entergy Texas, Inc., for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744, Order at FOF 26(t) (Dec. 13, 20 I 0). The ratchet is applicable to the General Service (GS), General Service - Time of Day (GS-TOD), Large General Service (LGS), Large General Service - Time of Day (LGS-TOD), Large Industrial Power Service (LIPS), and Large Industrial Power Service - Time of Day (LIPS-TOD). 949 TIEC Ex. 27 (Docket No. 37744 Stipulation and Settlement Agreement) at 6. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE290 PUC DOCKET NO. 39896 following is the relevant sections from that compliance tariff, which is applicable to Large Industrial Power Service (LIPS) customers (all customers taking service under this tariff are required to enter into a service agreement contract with ETI): VI. DETERMINATION OF BILLING LOAD The kW of Billing Load will be the greatest of the following: (A) The Customer's maximum measured 30-minute demand during any 30-minute interval of the current billing month, subject to§§ III, IV and V above; or (B) 75% of Contract Power as defined in § VII; or (C) (1) For existing accounts with contracts for service for loads existing prior to August 15, 2010 - 60% of the Highest Contract Power established prior to August 15, 2010 as defined in § VII, (2) For new accounts with contracts for service for loads not existing prior to August 15, 2010 - Does Not Apply; or (D) 2,500 kW. VII. DETERMINATION OF CONTRACT POWER Unless Company gives Customer written notice to the contrary, Contract Power will be as defined below: Highest Contract Power - the greater of (i) the highest Billing Load established under the currently effective contract, or (ii) the kW specified in the currently effective contract. Contract Power- the highest load established under § VI (A) above during the 12 months ending with the current month. For the initial 12 months of Customer's service under the current! y effective contract, the Contract Power shall be the kW specified in the currently effective contract unless exceeded in any month during the initial 12-month period. 950 In this case, ETI changed the tariff provisions for all customers: VI. DETERMINATION OF BILLING LOAD The kW of Billing Load will be the greatest of the following: (A) The Customer's maximum measured 30-rninute demand during any 30-minute interval of the current billing month, subject to§§ III, IV and V above; or (B) 75% of Contract Power as defined in§ VII; or 950 TIEC Ex. 29 (Tariff Approved in Docket No. 37744)(emphasis added). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE291 PUC DOCKET NO. 39896 (C) 2,500 kW; or (D) 60% of the kW specified in the currently effective contract. VII. DETERMINATION OF CONTRACT POWER Unless Company gives Customer written notice to the contrary, Contract Power will be as defined below: Contract Power shall be the highest load established under§ VI(A) above during the 12 months ending with the current month. For the initial 12 month& of Customer's service under the currently effective contract, Contract Power shall be the kW specified in the currently effective contract unless exceeded in any month during the initial 12-month period. 951 The contested issue concerns ETI' s new language. ETI maintains the new language is not a life-of-contract ratchet. Commission Staff, TIEC, and DOE disagree. Stated simply, Department of Energy (DOE) witness Dwight D. Etheridge testified that the introduction of the term "kW specified in the currently effective contract" transforms what was a 12-month ratchet into a life-of-contract ratchet. 952 At the outset, the AUs note that some of ETI's proposed tariffs do comply with the stipulation in the prior case. ETI eliminated the life-of-contract provisions for the GS and GS-ToD customer classes. However, ETI' s new language for the remaining ratchet classes, according to Staff witness Mr. Abbott, has the effect of maintaining a slightly different type oflife-of-contract demand ratchet. 953 The discussion in this section applies to the LIPS class but the same argument follows for LGS and GS classes. The parties contesting ETI' s demand ratchet language argue that: ( 1) ETI' s compliance tariff in Docket No. 37744 was consistent with the parties' agreement; (2) ETI' s proposal imposes a life- of-contract demand ratchet; (3) the service agreement and tariff are linked; and (4) the new demand ratchet is not equitable or cost-based. These arguments are set out below. 951 ETI 67 (Talkington Direct) at Ex. MLT-R-4 at 15 (emphasis added). ETI changed the relevant language in its tariff in its rebuttal testimony. Thus, the testimony of Messrs. Etheridge and Abbott can be slightly confusing because these witnesses address the tariff initially proposed by ETI. 952 DOE Ex. l (Etheridge Direct) at 11. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE292 PUC DOCKET NO. 39896 > The agreed tariff from Docket No. 37744 was consistent with the parties' agreement and shows how UPS billing load should be calculated. Staff, TIEC, and DOE agree that when ETI filed the compliance tariff in Docket No. 37744, the only demand ratchet that remained in the LIPS tariff for ETI' s new customers was a 12-month demand ratchet. ETI removed the life-of-contract ratchet that set a perpetual obligation for a customer to pay for power based on its highest contract power or a percentage of its contract power. Staff, DOE, and TIEC argue that ETI' s action in removing those provisions was consistent with the agreement and is evidence of what ETI should have done in this case. They contend that ETI witness Ms. Talkington agreed that the settlement eliminated both the highest load established under the currently effective contract and the amount specified in the contract.954 in other words, the compliance tariff tracked the agreement. ETI does not directly respond to this argument: Ms. Talkington did not address this in her rebuttal testimony. However, ETI states that the AI.Js should "not be distracted by ETI's initial error of unintentionally removing the contracted capacity provision as to new customers in its compliance tariffs in Docket No. 37744."955 Apparently, ETI believes that the tariffs it filed in compliance with the Docket No. 37744 agreement were in error. > ETI proposes a demand ratchet in this case that is based on the contracted quantity stated in the tariff-required service agreement. All parties agree that what ETI proposes in this docket is different from the Docket No. 37744 tariff, as evidenced by Ms. Talkington: Q: So last time, when the company and the parties implemented the elimination of the life-of-contract ratchet, it eliminated the 60 percent ratchet applicable to both actual demand during the contract period or the contract - the amount specified in the contract. A. Yes, the way it's put in the schedule, yes. 953 Staff Ex. 7 (Abbott Direct) at 16-19. 954 Tr. at 1432. 955 ETI Reply Brief at 9 l. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE293 PUC DOCKET NO. 39896 Q: And that's different than what you proposed in this case? A: It is. Q: And do you apply a different meaning to the agreement of what the life of contract ratchet meant than was applied in the tariff? A: Yes. What we have in this case is that the life-of-contract power relates to the highest load established under the currently effective contract ... 956 According to ETI, its proposed language does not impose life-of-contract ratchet, as defined by Mr. Pollock in Docket No. 37744 or by Messrs. Etheridge and Abbot in this case. Witness Definition Pollock "A life-of-contract ratchet is based on the highest demand ever imposed by a customer during the term of the contract." He further explained that ETI' s proposed Docket No. 37744 tariff had "a life-of-contract ratchet [which] imposes a perpetual obligation to pay a minimum demand charge throughout the term of the contract."957 Etheridge "A life-of-contract ratchet is a ratchet where you're not looking solely at current loads but some other loads in some prior period, so it creates a perpetual obligation to pay."958 Abbott "[A] life of contract demand ratchet, which is based upon the highest demand established in the time period.... is one type of life-of-contact demand ratchet" 959 ETI argues that the above definitions all make reference to the demand actually imposed by the operations of the customer's physical plant. But the contracted quantity provision it proposes is a minimum kW amount contractually agreed between the two parties to the service agreement, which is a required contract between the customer and ETI. 960 ETI argues the provision is not set by actual events during the term of the contract or in a prior period of the term of the contract, or in a monthly or 30-minute time period within the term of the contract; rather, it is set in the contract: 956 Tr. at 1432-1433 (emphasis added). 957 DOE Ex. 3 (Docket No. 37744 testimony excerpt) at 5-6. 958 Tr. at 2004. 959 Tr. at 1817. 960 Mr. Etheridge testified that customers taking service under Schedule LIPS must sign a contract for service. Tr. at 1991. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE294 PUC DOCKET NO. 39896 That contracted quantity is set as, to use Mr. Etheridge's words, "an estimate" that cannot be unilaterally changed by the Company; instead, a change to that kW amount could only be made through negotiation between the two parties or through a proceeding before the Commission. To use Mr. Pollock's definition, it is not a demand "imposed by the customer during the term of the contract." It is instead a fixed, contractually agreed to amount that is set as a condition of service prior to the contract term. 961 In sum, ETI argues the provision in question are not life-of-contract ratchets that lock the customer into the highest demand ever imposed by the customer's actual load during the term of the contract. Rather, they are, at most, 12-month ratchets that set the billing demand over a 12-month period, but not the life of the contract, at 7 5 percent. Staff suggests that the Commission does not, fortunately, have to determine what contract provision may or may not constitute a life-of-contract demand ratchet. Rather, the Commission must ensure that ETI fulfilled its obligations under the Docket No. 37744 settlement. Staff believes that the parties to that settlement understood the meaning of the life-of-contract term, ETI followed through with compliance tariffs that evidenced its understanding, and now ETI should be required to stick with its agreement. )- The service agreement and tariff are linked. According to TIEC, ETI tries to make the argument that its proposal is justified because ETI and its large customers may sign an agreement for service that specifies a customer's contract power. This does not justify ETI' s proposal because ETI' s form "Agreement for Electric Service" expressly states that the agreement is subject to the terms of "applicable rate schedules."962 Thus, maintains TIEC, the LIPS tariff billing load provisions impact a customer's contract power and can reasonably reduce a customer's billing load below its contract power if the customer has a reduction in load lasting longer than 12 months. 961 ETI Initial Brief at 211 (footnotes omitted), citing Tr. at 1994, 2012. 962 ETI Ex. 3, Schedule Q 8.8 at l 1.1.  ~~-~·----------- SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE295 PUC DOCKET NO. 39896 ETI' s proposal should be rejected, argues TIEC, because it would allow the utility to indefinitely seek revenue from a customer that has nothing to do with the customer's actual usage or the utility's costs. For example, if a plant took 150 MW of load in its heyday, under ETI' s proposal, the plant would be obligated to pay demand charges based on 60 percent of its original contract power. This is because ETI' s standard agreement requires the utility's "express approval" to set a new contract power and the utility therefore could choose not to negotiate (or negotiate in a timely manner) a new contract power. 963 If LIPS billing load is tied to contract power, then its customers would be completely at its mercy to negotiate a reasonable contract power based on the customer's actual usage for the time period. TIEC contends this is a ridiculous result and would render the parties' agreement to eliminate the life-of-contract ratchet meaningless. > ETI's new demand ratchet is not equitable or cost-based. TIEC does not dispute that a 12-month ratchet is reasonable. However, Mr. Pollock, in Docket No. 37744, explained why a perpetual obligation to pay demand costs for load that the utility does not serve is objectionable: While it is appropriate to require customers to pay for the facilities they use, a perpetual obligation is both extreme and unnecessary. Typical demand ratchets reach back twelve months. A life-of-contract ratchet can reach back decades. This is particularly inappropriate when longstanding customers have permanently reduced operations. A customer that has reduced operations is not purchasing the same level of generation and transmission services as in the past, nor is ETI procuring the same level of generation and transmission services for the customer. Further, because of load growth on the ETI system, the capacity no longer being used by the customer would be used by other customers. Thus, a life-of-contract ratchet does not properly reflect cost-causation. 964 > Witness Recommendations. Staff witness Mr. Abbott recommended that ETI be required to eliminate from its LGS, LGS-ToD, LIPS, and LIP-ToD tariffs the language that results in a ratchet based upon the current 963 ETI Ex. 3, Schedule Q 8.8 at 11.2. 964 DOE Ex. 3. SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE296 PUC DOCKET NO. 39896 effective contract-specific demand. Also, if the Commission approves Mr. Abbott's recommendation, he stated that the billing determinants used to calculate the rates for the affected customer classes will likely change. Therefore, ETI should be required to update the affected billing determinants and reflect the resulting change in its rates in the compliance filing of this docket.965 DOE witness Etheridge also recommends that same for the LIPS tariff. He specified language that will exclude the life-of-contract ratchet language and retain the existing rolling 12-month ratchet language in Schedule LIPS. 966 Specifically, he proposed the following: VI. DETERMINATION OF BILLING LOAD The kW of Billing Load will be the greatest of the following: (A) The Customer's maximum measured 30-minute demand during any 30-minute interval of the current billing month, subject to §§ III, IV and V above; or (B) [60%] of Contract Power as defined in § VII; or (C) 2,500 kW. VII. DETERMINATION OF CONTRACT POWER Unless Company gives Customer written notice to the contrary, Contract Power will be as defined below: Contract Power- the highest load established under § VI (A) above during the 12 months ending with the current month. For the initial 12 months of Customer's service under the currently effective contract, the Contract Power shall be the kW specified in the currently effective contract unless exceeded in any month during the initial 12-month period. )ii- AI.Js Recommendation. The ALls find that ETI violated its agreement with the signatories in Docket No. 37744: the tariff language proposed by ETI is a life-of-contract demand ratchet. ETI failed to explain how the compliance tariffs adopted in Docket No. 37744 were in error. ETI' s argument that its new language is not a life-of-contract demand ratchet was unpersuasive. To justify its modification, ETI relied 965 Staff Ex. 7 (Abbott Direct) at 20. 966 ETI can adopt similar language for its LGS, LGS-ToD, LIPS, and LIP-ToD tariffs. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE297 PUC DOCKET NO. 39896 only on a portion of Mr. Pollock's Docket No. 37744 definition. Moreover, both Messrs. Abbott and Etheridge were unequivocal that ETI, contrary to its agreement in the previous rate case, is imposing a life-of-contract or perpetual obligation to pay. Finally, the weight of the evidence supports a finding that the demand ratchet ETI proposes in this case is not equitable or cost based. The ALls recommend that ETI' s proposed LIPS tariff be amended to include the language proposed by Mr. Etheridge. The ALls concur with Mr. Etheridge that, with such language, ETI has a financial incentive to negotiate the maximum possible contracted level of capacity, not the minimum, and the result is consistent with the Docket No. 37744 agreement. 3. Large Industrial Power Service (LIPS) TIEC witness Pollock explained that Schedule LIPS recovers base rates through a seasonally adjusted demand charge (per kW) and a two-step non-fuel energy charge (per kWh). The demand charges are also adjusted (either up or down) to reflect the differences in costs by delivery voltage. ETI' s existing LIPS schedule has no customer charge. In its initial filing, ETI removed all purchased power capacity costs from base rates and proposed recovering them through a PPR as a demand charge. When it did so, the proposed demand charges were increased, but the proposed non-fuel energy charges were substantially reduced. Following the Supplemental Preliminary Order, which removed the PPR from further consideration, ETI proposed to roll these costs back into base rates. The resulting rebundled demand and energy charges would increase by about the same percentage.967 Mr. Pollock testified that the proposed structure of Schedule LIPS does not track costs as derived in ETI's class cost-of-service study. Specifically, he complained: (1) there is no customer charge, despite the fact that the customer costs allocated to the LIPS class would translate into a monthly rate of over $6,000, and (2) the proposed non-fuel energy charges would recover a significant amount of demand related costs. According to Mr. Pollock, production/transmission demand-related costs are $8.47 per kW, and distribution costs add another $0.99 per kW, for a total of $9.46 per kW. The proposed LIPS demand charges are $7.07 per kW for transmission delivery and an additional $1.82 for distribution service, for a total of $8.89 per kW. Thus, in Mr. Pollock's 967 TIEC Ex. L (Pollock Direct) at 68-69. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE298 PUC DOCKET NO. 39896 opinion, the proposed demand charges (given ETI's requested rate increase) are too low. By contrast, he noted, non-fuel energy costs are about 0.226¢ per kWh, while the proposed non-fuel energy charges would average over 0.600¢. Thus, these charges are 2.5 times higher than the non-fuel energy costs based on ETI's filing. 968 (a) A New Customer Charge TIEC urged that any increase in Schedule LIPS should be used to create a customer charge. Mr. Pollock calculated that a cost-based customer charge should be about $6,050 per month, and he recommended an initial customer charge of $6,000 per month. This would collect approximately $5.9 million ($6,000 x 984 bills). He added that any remaining increase not accounted for by the initial customer charge should be collected in the demand charges. He also stated that the non-fuel energy charges should not be changed unless the LIPS class is allocated less than a $5.9 million increase. In that event, he recommended that the non-fuel energy charges should be decreased. This would gradually correct the imbalance between the below-cost demand charges and above-cost energy charges. Mr. Pollock further stated that the delivery voltage adjustment applicable to distribution service should be retained so that the rate better reflects the cost. Should the LIPS class not receive an increase or if base rates are decreased, Mr. Pollock recommended that the customer charge should be reduced proportionally. Any remaining revenue surplus should be applied to reduce the non-fuel energy charges to cost and then to reduce the demand charges. 969 Staff witness Abbott also recommends the introduction of a customer charge, but a much smaller one than that recommended by Mr. Pollock- $630. 970 DOE supports Staff's proposed $630 customer charge. DOE witness Etheridge testified that TIEC' s proposed $6,000 customer charge far exceeds a reasonable initial customer charge for Schedule LIPS. For example, the existing Commission-approved monthly customer charge for 968 TIEC Ex. I (Pollock Direct) at 69-70. 969 Id. at 70. 970 Staff Ex. 7 (Abbott Direct) at 27. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE299 PUC DOCKET NO. 39896 Schedule LGS is $425.05. Mr. Etheridge stated that the introduction of a $6,000 customer charge will lead to large shifts in intra-class revenue responsibility from high load factor customers to low load factor customers because a customer charge does not vary with usage. He noted, as an example, that TIEC's proposal would increase DOE's Big Hill annual costs by $72,000 or nearly 10 percent. Moreover, Mr. Etheridge pointed out that two parties are proposing to lower the Schedule LGS customer charge-approving either of these recommendations and TIEC' s would levy Schedule LIPS customers with a new customer charge that is over 23 times the level of the LGS class. He believes such inconsistencies are inexplicable. Additionally, such disparity would present 971 a challenge to any customer migrating from the LGS to the LIPS class. DOE witness Etheridge agreed that is appropriate to move toward cost-based rates, however, he indicated that gradualism should be properly applied to move rates toward cost without undue impact on low usage and low load factor customers in the LIPS class. If a new customer charge for the LIPS class is to be imposed-it should be that recommended by Commission Staff. 972 The Al.J s are persuaded by Mr. Etheridge' s testimony that the adoption of a $6,000 customer charge far exceeds ETI' s existing customer charge in the LGS Schedule and results in a significant and inappropriate impact to low load factor customers. Rather, Mr. Abbott's proposed customer charge of $630 is an appropriate charge to this customer class, particularly as ETI' s current rates applicable to LIPS customers do not include any customer charge. 973 (b) Demand and Energy Charges In an effort to move more towards cost-based rates, Mr. Abbott recommends a slight decrease 974 in the LIPS energy charges and an increase in the demand charges from current rates. Mr. Pollock does not recommend an increase in energy charges. However, he recommends increasing demand 971 DOE Ex. 2 (Etheridge Cross-Rebuttal) at 3-4. 972 DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5. 973 TIEC Ex. 1 (Pollock Direct) at 70. 974 Staff Ex. 7 (Abbott Direct) at 27. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE300 PUC DOCKET NO. 39896 charges to cover any remaining revenue increase for the LIPS class that is not accounted for with the customer charge. He suggested that such a change will gradually correct the imbalance between the below-cost demand charges and above-cost energy charges. 975 DOE witness Etheridge expressed concerns with both proposals. He stated that Schedule LIPS customers are, on average, substantially more energy intensive than customers taking service under Schedule LIPS-TOD customers. He indicated that TIEC's proposed rate design (with the $6,000 customer charge) would double the cost increase associated with base rates and the fuel factor for LIPS-TOD customers compared with the average cost increase for the class as a whole. Customers with lower load factors than Schedule LIPS-TOD customers would fare even worse. 976 Mr. Etheridge also was concerned about Staffs proposed charges, noting that Mr. Abbott failed to explain how the slight decrease in the LIPS energy charge and the large increase in the demand charge would affect customers with changes in the revenue requirement ultimately assigned to the class. Mr. Etheridge stated that even Staffs proposed changes will noticeably shift intra-class cost responsibility toward Schedule LIPS customers with relatively low load factors. To address his concern that changes in the revenue requirement may have a significant impact even with Staffs gradual movement in rates, Mr. Etheridge recommended that Staffs proposal should set the limit on intra-class cost responsibility shifts. 977 The ALls find evidentiary support for and recommend the adoption of Mr. Abbott's proposed changes to Schedule LIPS. There is sufficient evidence, based on Mr. Pollock's testimony, that Mr. Abbott's suggested changes gradually move the rates towards cost without the risk of rate shock. TIEC' s demand and energy proposals result in unreasonable large shifts in intra-class revenue responsibility. However, the ALls also agree with Mr. Etheridge that Staffs proposal may need to be adjusted depending on the ultimate revenue requirement adopted. 975 TIEC Ex. 1 (Pollock Direct) at 70. 976 DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5. 977 DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE301 PUC DOCKET NO. 39896 4. Schedulable Intermittent Pumping Service (SIPS) DOE proposes that a new rider, Schedulable Intermittent Pumping Service (SIPS), be included in the LIPS tariff. This will allow DOE and other customers with intermittent pumping loads to avoid application of a demand ratchet to schedulable, temporary, increased demand during off-peak months when ETI's costs are lowest. DOE suggests that the proposed rider will allow the DOE to schedule important testing and oil exchanges, when possible, during off-peak months, is consistent with existing riders, and does not adversely impact other customers. DOE explained that its Strategic Petroleum Reserve (Reserve) Texas sites-Big Hill in Jefferson County and Bryan Mound in Brazoria County-play an important role in ensuring the energy security of the United States. With a crude oil inventory of about 726.5 million barrels in 2010, the Reserve is the largest emergency supply of oil in the world. The Reserve was established by Congress as a result of the oil supply disruption in the early 1970s.978 DOE witness Etheridge testified that DOE takes service to its Big Hill site under Schedule LIPS at an annual cost of approximately $770,000. Mr. Etheridge explained that the Reserve' s sites typically operate in standby mode, with routine cyclical tests of pumping equipment. The largest of these tests is performed every other year. These cyclical equipment tests can be coordinated with ETI so that they occur during low peak periods. 979 On rare occasions, the Reserve can also be tapped. In its nearly 35 years of operations, there have been three Presidential-ordered drawdowns: January 1991, the beginning of Desert Storm; September 2005, Hurricane Katrina; and July-August 2011, the International Energy Agency coordinated release. The latter was the largest of the three drawdowns at 30.6 million barrels. Additionally, the Reserve has provided support to the oil industry in localized emergency or operational situations involving a disruption in supply, such as ship channel closures and hurricanes. 978 DOE Ex. I (Etheridge Direct) at 3. 979 DOE Ex. I (Etheridge Direct) at 3-4 SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE302 PUC DOCKET NO. 39896 When oil is exchanged during these situations, the Reserve will operate pumps at higher levels than would occur during normal standby operations. 980 Mr. Etheridge proposed a rider to Schedule LIPS where maximum demands during pre- scheduled, non-summer month operations of a limited duration are not subject to demand ratchets. For this new rider, he proposed that the non-summer months be classified as October through May to give customers and ETI more flexibility. (Under Schedule LIPS, non-summer months are November through April.) Key provisions of the proposed SIPS rider include: A requirement that customers schedule with ETI limited duration operations during non-summer months four weeks in advance. ETI must approve scheduled operations. Operations would not be allowed to exceed 10,000 kW in magnitude nor last for more than 80 hours per year. ETI could cancel operations at any time if a capacity constraint develops. If a customer failed to comply, the customer would incur costs associated with ETI' s ratchet. A customer in compliance would not be subject to ETI' s demand ratchets for loads established during those operations, but would pay the demand charge in the month in which the operations occur. 981 Mr. Etheridge gave an example of charges under Schedule LIPS versus charges if the rider were adopted. In September 2010, Big Hill conducted a test and established a maximum measured demand of 11,640 kW, well above the site's average maximum demand of approximately 3,000 kW. DOE paid demand charges on the 11,640 kW in September 2010. In October 2010, ETibilled DOE for 75 percent of that level of demand or 8,730 kW based on the rolling 12-month ratchet. Its actual demand was 2,520 kW. In terms of actual costs, DOE paid $683,000 for its September usage. Under the 75 percent ratchet, DOE would pay $609,000 per month. Mr. Etheridge estimated that the 980 DOE Ex. 1 (Etheridge Direct) at 3-4. 981 DOE Ex. 1 (Etheridge Direct) at 18. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE303 PUC DOCKET NO. 39896 charges amounted to $59/k:W per year, which could easily represent nearly one-half of the annual carrying cost of a combustion turbine. Whereas, under the proposed rider, if DOE conducted the test in February as it intended to, it would have paid ETI for the 11,640 kW level of demand, but the usage would not be used in conjunction with ETI' s ratchets. Mr. Etheridge concluded ETI' s tariff is not equitable. At the hearing, Mr. Etheridge estimated that the rider's impact on other customer classes at approximately $500,000, where Schedule LIPS base rate revenues are approximately 982 $110 million. According to DOE, for 15 years, June 1996-June 2011, ETI, by contract, accommodated the Reserve's intermittent load by allowing the DOE to, once annually, "reset" the demand level to be used by ETI when applying demand ratchets. The DOE was able to avoid significant demand charges when typical demand was very low. After June 2011, ETI declined to apply the terms of the long-time contract and allow the reset. DOE concedes that cost-based rates to reflect the Reserve' s unique operations should ultimately be addressed by contract and/or new tariffs. DOE notes that the very purpose of some riders is to address specific customer characteristics. For instance, Standby and Maintenance Service is available only to those customers that co-generate electricity; the Optional Rider to Schedule LIPS for Pipeline Pumping Service alters the designation of on peak-hours only for customers with pipeline pumping stations. Other riders, claims DOE, seek a win-win for all customers. For instance, the Rider to LIPS for Planned Maintenance rewards customers for scheduling routine maintenance and idling facilities during ETI' s peak summer months of June through September by waiving the demand ratchet. DOE argues that the proposed SIPS rider mirrors Planned Maintenance by waiving the demand ratchet if customers are able to schedule intermittent loads outside of ETI's peak summer months. Moving toward cost-based rates is not discriminatory, claims DOE. Nor is rewarding customers who use their load scheduling flexibility for the benefit of all customers. DOE's proposed SIPS rider is opposed by ETI, TIEC, and Staff. 982 DOE Ex. I (Etheridge Direct) at 19-20; Tr. at 2034. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE304 PUC DOCKET NO. 39896 ETI witness Talkington testified that the actual Reserve load, as Mr. Etheridge described, does not appear to match the parameters of his proposed SIPS rider. As recently as July and August 2011, the Reserve sites had significant load requirements in order to pump vast quantities of oil. She further testified that the Reserve loads are random in occurrence and are significant. ETI must at all times maintain generation resources to meet this significant and randomly occurring load. In addition, the Company has invested in transmission and other facilities to serve this customer even if there is no or very little consumption. She believed it would not be appropriate or equitable to other customers to remove or forgive the 12-month ratchet provision after the Company made these investments to serve the Reserve and while the Company has maintained generation to meet its load. If the 12-month ratchet were forgiven, then the costs incurred to serve DOE would have to be borne by other customers in the LIPS rate class. 983 TIEC witness Pollock complained that Mr. Ethridge failed to analyze the impact on other LIPS customers. Mr. Pollock contended the rider would discriminate against both Schedule LIPS customers (by redefining the summer billing period) and Schedule SMS customers (whose ability to schedule maintenance power could be subordinate to LIPS customer taking advantage of the new Rider). 984 Staff is concerned that the rider's unusual eligibility requirements-that a customer must schedule load four weeks in advance, limit the high load occurrence to "off-peak months" (which is redefined in the rider), and limit the yearly hours of load-indicate it is tailored solely to meet the unique needs of the Reserve. According to Staff, DOE conceded that, although other customers with intermittent loads might take advantage of the proposed SIPS rider, Mr. Etheridge was not aware of any other actual customer that could do so. 985 Staff argues the rider appears to offer unreasonably preferential treatment to the DOE and should be rejected. 983 ETI Ex. 67 (Talkington Rebuttal) at 41. 984 TIEC Ex. 3 (Pollock Cross Rebuttal) at 9-10, 44-46. 985 Tr. at 2008 ("Q: Now, who else would take advantage of this SIPS rate schedule, other than DOE? A: It's written such that any other customer that would have an intermittent schedulable load could take advantage of it. But I'm not sure if there are other customers on Entergy' s system that could take advantage of it. Q: So you SOAR DOCKET N O . - PROPOSAL FOR DECTSION PAGE305 PUC DOCKET NO. 39896 Beyond issues of discrimination, Staff is also concerned that the rider would shift costs from the DOE to other LIPS customers. Although DOE indicates that any shift would have a small overall impact on the LIPS class, Staff argues that the Commission should not endorse any discriminatory rate rider. Although Staff and TIEC claim the proposed rider is discriminatory, other riders applicable to Schedule LIPS customers are available at different times of the year as well (Planned Maintenance is available only during the months of June through September) and others are limited to customer-specific needs-such as PPS for pipeline customers. Mr. Etheridge testified that this rider could apply to any customer-it is not restricted solely to the DOE. The ALJs do not find this rider to be unreasonably discriminatory. As to ETI' s concern on this issue, it was focused on whether the DOE' s load met the proposed rider's requirements. However, if a customer taking service under the rider is unable to schedule its maintenance and oil exchanges with ETI, then the usage would be under the SIPS Schedule and the SIPS tariffed demand ratchet would apply. Moreover, Mr. Etheridge testified that the impact on other customer classes is limited. As to ETI' s cost recovery, the LIPS rider customers will pay a demand charge to cover the costs they impose on the system in the month SIPS service is taken. The ALJs agree with DOE that the SIPS rider is reasonable and should be adopted. 5. Standby Maintenance Service (SMS) TIEC witness Pollock explained that Schedule SMS applies to customers that use self-generation to supply a portion of their electricity requirements. These customers contract with · ETI for either standby and/or maintenance power service to replace capacity or energy normally generated by the customer's on-site generation. Standby (or backup) power is electric energy or capacity supplied to replace energy or capacity that is unavailable due to an unscheduled or forced outage of the facility. Thus, backup power must be available at any time. Maintenance power is electric energy or capacity supplied during a scheduled outage. Unlike backup power, maintenance power must be arranged with 24-hour notice and only during such times and at such locations that, in don't know that there are others who could use it. This could apply just to DOE? A: It could."). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE306 PUC DOCKET NO. 39896 ETl' s opinion, will not result in adversely affecting or jeopardizing firm service to other customers, prior commitments, or commitments to other utilities. In addition, the customer must make arrangements and schedule maintenance power in writing in advance and confirmed in writing by ETI. ETI can also limit requests for maintenance power and allocate and schedule available service, if requests are made from more than one customer. Thus, Mr. Pollock stated that maintenance power is of a lower quality of service than backup or standby power. He also indicated that, because the Company can limit the amount of maintenance power, it is more likely that customers would prefer 986 to schedule maintenance power during the non-summer months. ETI witness Talkington explained that standby service includes both the readiness to serve and the actual delivery of power and energy delivered when a customer requires service due to a forced outage or a planned maintenance period. She indicated that many utilities offer a combination of pricing and terms for demand and energy service as well as a form of reservation charge dealing with the readiness to serve. She further indicated that the actual rate design may differ, but standby tariffs usually contain provisions for back-up (forced outage) or maintenance (planned outage). She concluded that ETI' s current rate schedule provides for these features, and ETI is not proposing to change Schedule SMS in this proceeding.987 TIEC proposes to redesign SMS service to better reflect the cost characteristics of standby and maintenance power customers. Mr. Pollock provided his analysis to support TIEC's position. Under the current Schedule SMS, customers pay a monthly demand (or billing load) charge of $1.12 per kW for backup power. The corresponding charges for maintenance power are $1.12 per kW for outages during the summer months (May through October) and $0.84 per kW for outages during the non-summer months. Thus, the non-summer month charge is 75 percent of the summer month charge. Energy is priced under an array of time-differentiated charges, as shown in the table below: 988 986 TIEC Ex. l (Pollock Direct) at 70-71. 987 ETI Ex. 67 (Talkington Rebuttal) at 19-20. 988 TIEC Ex. 1 (Pollock Direct) at 72-73. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE307 PUC DOCKET NO. 39896 Current Schedule SMS Non-Fuel Energy Charges (¢per kWh) Delivery Voltage On-Peak989 Off-Peak Distribution (less than 69KV) 3.386¢ 0.514¢ Transmission (69KV and !:!l'eater) 2.334¢ 0.211¢ Mr. Pollock examined P.U.C. SUBST. R. 25.242(k)(l) and concluded that, for Standby Service, cost-based standby rates should recognize system-wide costing principles and must not be discriminatory. According to his analysis, the SMS demand charges should be $0.82 per kW for delivery at transmission and $2.64 per kW for delivery at distribution. He also determined that cost- based energy charges should be as follows: 990 Cost-Based Schedule SMS Non-Fuel Energy Charges (¢per kWh) Delivery Voltage On-Peak Off-Peak Distribution (less than 69KV) 0.955¢ 0.639¢ Transmission (69KV and !:!l'eater) 0.916¢ 0.614¢ Mr. Pollock explained that, on average, 7 percent of Schedule SMS billing demand was coincident with ETI's summer month system peaks. This compares to 74 percent for Schedule LIPS; thus, the ratio of the SMS to LIPS coincidence factors is 12 percent. By Mr. Pollock's calculations, the resulting demand charge for transmission service would be $0.82 per kW ($7.07 x 12 percent), and the corresponding SMS distribution demand charge would be the sum of the transmission charge and the Schedule LIPS distribution demand charge, or $2.64 per kW ($0.82 + $1.82). 991 989 On-peak hours are from 1:00 p.m. to 9:00 p.m., Monday through Friday of each week, beginning on May 15 and continuing through October 15. In addition, fuel charges are priced at avoided energy cost as calculated under Schedule LQF. TIEC Ex. 1 (Pollock Direct) at 72. 990 TIEC Ex. 1 (Pollock Direct) at 73-74 and Ex. JP-15. 991 Id. at 72-74. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE308 PUC DOCKET NO. 39896 Mr. Pollock testified that he combined production and transmission costs in deriving a cost-based schedule SMS demand charge for transmission delivery, because both production and transmission demand-related costs are allocated to customer classes using the A&E 4CP method. This method recognizes that production/transmission plant is sized to meet the diversified summer peak demands of all ETI customers. That is, Mr. Pollock stated, the 4CP demands are a primary driver of the costs of the power plants, PPAs, and transmission facilities. As noted above, Mr. Pollock contended and verified by analysis that a cost-based Schedule SMS demand charge 992 should be only 12 percent of the corresponding demand charge for Schedule LIPS. Mr. Pollock also stated that he proposed to differentiate the standby demand charge by delivery voltage because it more directly recognizes the different costs to provide service at transmission and distribution voltage. He added that this recommendation is consistent with the current Schedule SMS energy charges. 993 However, Mr. Pollock did not apply the 12 percent coincidence ratio to determine the distribution-related schedule SMS demand charge. He explained that distribution facilities are electrically closer to customers, so a customer's peak demand determines how distribution facilities must be sized to ensure reliable service. He stated that ETI recognized this driver by using maximum diversified demand to allocate distribution demand-related costs. For this reason, Schedule SMS customers require the same amount of distribution capacity as a similarly sized Schedule LIPS customer. Thus, according to Mr. Pollock, the Schedule SMS distribution demand charge should be the same as the corresponding Schedule LIPS demand charge. 994 Concerning energy charges, Mr. Pollock testified that the Schedule SMS energy charge should reflect the composite Schedule LIPS energy charges, or 0.614¢ per kWh. In his view, a Schedule SMS customer should also pay additional demand charges during on-peak hours, because this would recognize that an SMS customer that purchases more energy during on-peak hours would more closely resemble a LIPS customer. For this reason, cost-based on-peak energy charge should 992 Id. at 75-77. 993 TIEC Ex. 1 (Pollock Direct) at 77. 994 Id. at 77-78. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE309 PUC DOCKET NO. 39896 be a composite of the Schedule LIPS energy charge and the remaining demand charges (not collected in the SMS demand charge). He calculated an additional on-peak energy charge of 0.303¢, which yields a total on-peak energy charge of 0.917¢. Under this structure, an SMS customer that experiences an outage would pay approximately the same for electricity as a LIPS customer.995 In summary, Mr. Pollock contended that Schedule SMS should be reduced to more closely reflect the cost of providing standby service as follows: 996 Cost-Based Schedule SMS Charges Based on ETI' s Proposed Schedule LIPS Design Distribution Transmission Charge (less than 69kV) (69kV and greater) Billing Load Charge ($/kW) Standby $2.64 $0.82 Maintenance $2.44 $0.62 Non-Fuel Enenzv Char e (¢/kWh) On-Peak 0.955¢ 0.916¢ Off-Peak 0.639¢ 0.614¢ Using his recommended Schedule LIPS rate design, he proposed Schedule SMS charges shown in the table below: 997 TIEC Proposed SMS Charges Distribution Transmission Charge (less than 69kV) (69kV and greater) Customer Charge $6,000 (Stand Alone) Billing Load Charge ($/kW) Standby $2.46 $0.79 Maintenance $2.27 $0.60 Non-Fuel Energy Charge (¢/kWh) On-Peak 0.881¢ 0.846¢ Off-Peak 0.575¢ 0.552¢ 995 Id. at 77-78; Ex. JP-15. 996 Id. at 79. 997 TIEC Ex. l (Pollock Direct) at 80. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE310 PUC DOCKET NO. 39896 Mr. Pollock based his recommended charges on ETI' s proposed revenue requirements and class revenue allocation. If the Schedule LIPS revenue requirement is reduced, the charges should be correspondingly reduced. Mr. Pollock also added a customer charge, but he stated that the customer charge should not apply if a Schedule SMS customer also purchased supplementary power under another applicable rate. 998 To determine maintenance power charges, Mr. Pollock maintained the same relationship; that is, the current maintenance power demand charge is 75 percent of the standby power demand charge. He stated that the 75 percent should apply to the production/transmission component of the recommended standby power demand charge because distribution costs are caused by maximum demands occurring at any time, as previously discussed. This would result in a $0.20 and $0.19 per kW differential based on ETI's proposed and Mr. Pollock's recommended Schedule LIPS designs, respectively. 999 The AIJs note that Mr. Pollock's suggested changes to Schedule SMS are extensive. For instance, he introduced a $6,000 customer charge and, for the monthly billing load (demand) charges, he introduced separate rates for distribution and transmission customers. 1000 Ms. Talkington testified that Mr. Pollock erred in using load data for the period of 2007 through 2011 to develop a coincidence factor that he then uses to develop a lower back-up and maintenance demand charge for transmission-level customers, while significantly increasing the charge for distribution-level customers. She also stated that Mr. Pollock's proposal fails to recognize the "readiness to serve" aspect of standby service. ETI must be ready to serve the load represented by the largest generation unit taking standby service, plus account for the forced outage rates for all other existing customer-owned generators. 1001 998 Id. at 79. 999 TIEC Ex. 1 (Pollock Direct) at 80. 1000 TIEC Ex. 1 (Pollock Direct) at 80. 1001 ETI Ex. 67 (Talkington Rebuttal) at 20-21.  --- ; ' SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE311 PUC DOCKET NO. 39896 Ms. Talkington also stated Mr. Pollock failed to recognize that standby load does not lend itself to the typical rate design practices. She opined that the cost of providing SMS service is not driven only by the degree to which standby customers contribute to peak demand, but also by the Company's obligation to serve whenever called upon. This is the major reason Schedule SMS is not included in the development of allocation factors. 1002 Ms. Talkington admitted that she is not familiar with how ETI originally developed Schedule SMS, but stated that she knows that when a customer takes back-up or maintenance service, costing is generally designed to mimic what the customer would have paid on standard rates, absent the use of its own generator. She concluded that Mr. Pollock's analysis is over-simplified and incomplete. 1003 In rebuttal testimony, Ms. Talkington proposed a new rate design for SMS service, including a new service, Non-Reserved Service, which is an optional service designed to supplement Maintenance Service. ETI's new SMS proposal increases ETis test year base rate revenues by 53.27 percent, with an overall increase of $5.1 million. ETI did not include this rate increase in its notice. 1004 Accordingly, the ALls determine that ETI's new SMS proposal is not an option to be considered in this case. Commission Staff does not oppose ETI's request to retain its current Schedule SMS. ETI did not demonstrate how its current rates are just and reasonable. Rather, ETI' s evidence on the reasonableness of Schedule SMS is conclusory and insufficient in light of Mr. Pollock's testimony that the rates are not cost-based. Moreover, although Ms. Talkington indicated her concern with Mr. Pollock's analysis, she provided no quantitative support for her concern. The AUs, however, are concerned that Mr. Pollock's suggested changes are not accompanied by a rate 1002 ETI Ex. 67 (Talkington Rebuttal) at 21. 1003 ETI Ex. 67 (Talkington Rebuttal) at 21-22. 1004 PURA§ 36.102 and P.U.C. PROC. R. 22.51 require a utility to publish notice of its intent to change rates, with proposed revisions of tariffs and a detailed statement of each proposed change, the effect it is expected to have on revenues, the class and number of customers affected by the change. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE312 PUC DOCKET NO. 39896 impact analysis. And, as noted above, his suggested changes are extensive. Mr. Pollock's recommendations included a significant increase in the charge for distribution-level customers. Consistent with his Schedule LIPS recommendation, Mr. Pollock also included a $6,000 customer charge when no previous customer charge existed. Again, there is no analysis as to the effect such a charge would have on customer bills. The testimony of witnesses Benedict, Abbott, Higgins, and Pevoto caution that gradualism should be considered in rate design. As noted by Mr. Higgins, "full movement to cost-based rates in a single step is sometimes opposed on the grounds of intra-class rate impacts." 1005 However, the rate impact at this time is not known. Based on the evidence and discussion above, the AUs recommend adoption of Mr. Pollock's suggested changes to Schedule SMS , with the exception of a $6,000 customer charge. Consistent with the ALls' recommendation that a new LIPS charge of $630 is reasonable, the SMS charge should be limited to $630 and, as suggested by Mr. Pollock, not apply if a Schedule SMS customer also purchased supplementary power under another applicable rate. 6. Additional Facilities Charge (AFC) Mr. Pollock testified that Schedule AFC is the mechanism for charging customers directly for the costs of transformers, breakers and lines when those facilities provide service only to specific customers. Some of these facilities are booked to transmission accounts while others are booked to distribution accounts. Schedule AFC is applied as a percentage of the original (un-depreciated) cost of the facilities. 1006 TIEC contends that the Schedule AFC charges should be revised. According to Mr. Pollock, the current charges exceed ETI' s ownership and O&M costs; therefore, he recommended th<"\t the monthly charges in Schedule AFC be reduced. Under this rate schedule, there are two separate pricing options. Option A charges 1.49 percent per month; Option B applies when a customer elects to amortize the direct assigned facilities over a shorter term, ranging from one to ten years. Thus, the 1005 Kroger Ex. l (Higgins Direct) at 10. 1006 TIEC Ex. 1 (Pollock Direct) at 8 L SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE313 PUC DOCKET NO. 39896 Option B Monthly Recovery Tenn charge varies depending on the length of the amortization period of the directly assigned investment. A 0.453 percent Monthly Post-Recovery term charge also applies after a facility has been fully depreciated. ETI did not propose to change either the Option A or Option B charges in Schedule AFC. 1007 According to Mr. Pollock's analysis, charges imposed under Option A should be 1.20 percent per month under ETI's proposed revenue requirements. Under Option B, Mr. Pollock proposes various changes to the Recovery Tenn charges, and reduces the Monthly Post-Recovery term to 0 .3 5 percent per month. Further, if the Commission approves a lower base revenue requirement than ETI has proposed, Mr. Pollock stated that the recommended Schedule AFC charges (both Option A and Option B) should be reduced in proportion to any authorized reduction in ETI' s proposed rate of return, O&M expense, and property tax expense. 1008 In reaching this recommendation, Mr. Pollock used two different methods to derive a cost- based rate: a levelized cost analysis and a revenue requirement analysis. The former resulted in an Option A rate of 1.20 percent per month, and the revenue requirement analysis resulted in a weighted average rate of 1.18 percent. For Option B charges, Mr. Pollock also used a levelized cost analysis for each of the Option B amortization periods, which resulted in lower charges. 1009 ETI witness Talkington disagrees with Mr. Pollock's description of Schedule AFC. She testified that the rate schedule encompasses the costs associated with the installation of facilities other than those normally furnished. Or, under one option, the rates are like a monthly rental charge paid for facilities that would not normally be supplied by the Company. She also stated that Mr. Pollock's example of facilities (transformers, breakers and lines) is understated. 1010 1007 Id. at 82-85. 1008 TIEC Ex. l (Pollock Direct) at 81-85 and at Exs. JP-17 and JP-18. See ETI Ex. 3, Sch. Q-8-8 at 24. 1009 TIEC Ex. 1 (Pollock Direct) at Ex. JP-18. 1010 ETI Ex. 67 (Talkington Rebuttal) at 31. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE314 PUC DOCKET NO. 39896 ETI contends that revisions to this discretionary rate are unwarranted at this time. The Commission approved this rate structure (and rate) in Docket No. 16705. Moreover, ETI witness Talkington testified that this rate is voluntary-a customer has alternatives beyond those offered by ETI. Therefore, it is actually a market-driven rate. If a customer does not want to use this schedule to obtain the services it provides, the customer can secure services through other sources--either ETl-owned or otherwise. Ms. Talkington further stated that Mr. Pollock's suggested changes would be detrimental to the customers who do not have AFC rates because the AFC revenue is treated as an offset to the revenue requirement to the rate classes. 1011 Staff does not oppose ETI' s request to retain the AFC rate as it is currently designed. The ALls find insufficient support in the record to retain ETI's Schedule AFC as-is. As noted by TIEC, there is no evidence in this case to support ETI' s claim that: ( 1) the rate is a voluntary rate; (2) there are other options in the market for customers; or (3) that the rate continues to be based on a cost that the market will bear (as the Commission found years ago in Docket No. 16705). 1012 While Ms. Talkington disagreed with Mr. Pollock's proposal because he did not take into consideration the scope of facilities provided and that his proposal could be detrimental to other ratepayers because ETI' s revenues from this rate will decrease, she did not quantify her concems. 1013 The evidence supports a change to Schedule AFC that will move the rate more towards costs, and TIEC's proposals are the only ones for which there is evidence in the record. The ALls further agree with Mr. Pollock that his numbers should be reduced in proportion to any authorized reduction in ETI' s proposed rate of return, O&M expense, and property tax expense. 7. Large General Service (LGS) Kroger witness Kevin C. Higgins testified that the LGS rate schedule serves customers with monthly billing demands between 300 kW and 2,500 kW. ETI proposes to increase the LGS demand JOll ETI Ex. 67 (Talkington Direct) at 27-28. tol2 See Docket No. 16705, Final Order, FoFs 292-296. 1013 Tr. at 1437, 1439-1440. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE315 PUC DOCKET NO. 39896 charge from $8.56 per kW-month to $10.25 per kW-month and to increase the energy charge from $.00854 per kWh to $.01023 per kWh. The Company proposes no change in the customer charge of $425.05 per month. 1014 Mr. Higgins testified that ETI' s proposed LGS demand charge would recover only 72 percent of LGS demand-related costs. To compensate for the resultant revenue shortfall, the LGS energy charges proposed by ETI would significantly over-recover energy-related costs. Specifically, the overall LGS energy charge is proposed to be 428 percent of base energy costs. In addition, although the customer charge is proposed to be unchanged, it is set at 328 percent of cost. If, instead, the LGS customer charge were set at cost, it would only be $129.60 per month. 1015 Mr. Higgins illustrated his findings in the table below: 1016 LG Total Class Functionalized Cost Recovery Functions Costs Collected in (Under)/Over Percentage Rates Collection Recovered Demand $46,266,083 $33,116,674 $(13,149, 409) 71.6% Energ:v $3,6625,811 $15,556,253 $11,920,442 427.9% Customer $561,445 $1,841,316 $1,279,871 328.0% Total $50,463,339 $50,514,243 $50,904 Mr. Higgins stated that if a utility proposes a demand charge that is below the cost, it is going to seek to recover its class revenue requirement by over-recovering its costs in another area, typically through an energy charge that is above unit energy costs. In his opinion, for LGS, when demand charges are set below costs and energy charges are set above cost, customers with relatively higher load factors are required to subsidize the costs of lower load factor customers within the rate class. The subsidy is different for each higher load factor customer (a customer whose load factor is greater than the average for the rate schedule) and consists of the net increase in rates paid by these 1014 Kroger Ex. l (Higgins Direct) at 7. 1015 Id. at 8. 1016 Kroger Ex. 5. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE316 PUC DOCKET NO. 39896 customers as a result of setting energy charges above energy costs and demand charges below demand related costs. When the customer charge is set significantly above costs, smaller customers are overcharged and subsidize the larger customers. 1017 Recognizing that a full movement towards cost-based rates (without gradualism) in a single step may create intra-class rate impacts, Mr. Higgins proposed the following changes to better align costs: 1018 ETI Kroger Proposed %of Proposed %of Functions Charge Cost Charge Cost Demand ($/kW) $10.25 72% $12.81 90% Energy ($/kWh) $0.01023 428% $0.00513 216% Customer ($/Mo) $425.05 328% $260.00 201% Mr. Higgins developed his proposed rate impacts, which indicated a smaller rate impact on higher load factor customers than those with low load factors. He found them to be comparable to the rate impact found in ETI's proposed rates. 1019 ETI witness Talkington did not object to gradually moving rates toward setting demand energy and customer components closer to cost of service in the LGS class. !020 Based on principles of cost-based rates and of gradualism, Staff witness Abbott recommended a decrease in the LGS customer charge to $397 .02 from the current (and Company 1017 Kroger Ex. 1 (Higgins Direct) at 9. 1018 ld. at 10-11. 1019 ld. at 11, Ex. KCH-3. 1020 Tr. at 1452. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE317 PUC DOCKET NO. 39896 proposed) $425.05, and an increase in the energy charges, which is less than the increase proposed by the Company. 1021 The AUs found Mr. Higgins' proposed changes reasonable and well supported. Schedule LGS should be amended as proposed by Kroger. Schedule LGS also has a demand ratchet, and the AU s' recommendation for the elimination of ETI' s LIPS demand ratchet is applicable to this class. 8. General Service (GS) Based on principles of cost-based rates and of gradualism, Staff witness Abbott recommended a decrease in the GS customer charge to $39.91 from the current (and Company proposed) rate of $41.09. Staff also recommended a decrease in the energy charges. 1022 No party disputed Staffs recommendations, which the AU s adopt. Schedule GS also has a demand ratchet, and the AUs' recommendation for the elimination of ETI' s LIPS demand ratchet is applicable to this class. 9. Residential Service (RS) ETI' s RS rate schedule is composed of two elements: a customer charge of $5 per month and a consumption-based energy charge. The Energy charge is a fixed rate of 5.802¢ per kWh from May through October (Summer). In the months November through April (Winter), the rates are structured as a declining block, in which the price of each unit is reduced after a defined level of usage. For instance, the same energy charge of 5.802¢ applies, but only for each of the first 1,000 kWh consumed. Each kWh consumed beyond 1,000 is billed at a lower rate of 3.834¢. 1023 1021 Staff Ex. 7 (Abbott Direct) at 25-27. 1022 Id. 23 t0 OPC Ex. 6 (Benedict Direct) at 41, Ex. NAB-1, ETl's Response to State RFI No. 4-17; ETI Ex. 67 (Talkington Rebuttal) at 9. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE318 PUC DOCKET NO. 39896 ETI proposes to retain the general structure of the RS rate design but proposes an increase in the dollar amount of each rate element. OPC witness Benedict noted ETI' s proposed changes in his 1024 testimony, as set out below: ETI ETI Percent Rate Element Current Proposed Increase Customer Charge (per month) $5.00 $6.00 20.0% Energy Charge (Summer, all 25.3% $0.05802 $0.07268 kWh) Energy Charge (Winter, kWh S 25.3% $0.05802 $0.07268 1000) Energy Charge (Winter, kWh> 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 2.469¢ to 1024 OPC Ex. 6 (Benedict Direct) at 42. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE319 PUC DOCKET NO. 39896 1.645¢ 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 Prooosed 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 $0.05496 1000) Mr. Benedict stated that his proposal related to an intra-class rate design issue and was not intended to affect the amount of revenue to be collected from the residential class or any other class. If, however, the Commission approves a different revenue requirement for the residential class to reflect various proposed adjustments, rates for the class will need to be recomputed regarding a reduced block differential 1026 Staff generally agreed with OPC's recommendation for a reduction in the rate differential between the residential winter kWh :S 1000 block and the winter kWh> 1000 block, due to the inconsistency between the incentives produced under declining block rates and the State's energy efficiency goals. Staff witness Abbott stated that the extreme cold weather event of February 2011 demonstrated a need to incentivize wintertime energy efficiency measures, or at least a need to avoid encouraging excess energy usage. Therefore, Mr. Abbott agreed that some reduction in the rate block differential is warranted to better encourage wintertime energy conservation at the margin. 1027 ETI witness Talkington testified that the RS rates are cost-based with a declining block rate in winter. According to Ms. Talkington, residential load factors in winter increase as energy usage 1025 OPC Ex. 6 (Benedict Direct) at 43-45. 1026 OPC Ex. 6 (Benedict Direct) at 46. 1027 Staff Ex. 7 (Abbott Direct) at 27. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE320 PUC DOCKET NO. 39896 increases, and there is also a decrease in the fixed unit cost ($/kWh) as energy usage increases. She 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 ofETI'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 $7? 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 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. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE321 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 AUs 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 AU s 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 AUs 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- l 7.  --, SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE322 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-l2.5b-e, 1-21; 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)(l) 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; 33 io ETI Ex. 40 (Thiry Direct) at 7. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE323 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 lower 1034 Application of Gulf States Utilities Company to Reconcile its Fuel Costs, Docket No. 15102, Order on Rehearing at 2 (Jun. 24, 1997). SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE324 PUC DOCKET NO. 39896 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 Mcllvoy 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. Mcllvoy described how the gas buyers for ETI survey the markets and solicit offers for gas supplies. Ms. Mcllvoy 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. Mcllvoy 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 all fuel oil 1035 ETI Ex. 40 (Thiry Direct) at 18-21. 1036 ETI Ex. 39 (Cicio Direct) at 31-37. 1037 ETI Ex. 28 (Mcllvoy Direct) at 23, Ex. KDM-3. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE325 PUC DOCK.ET NO. 39896 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 generatio!l 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 BCil/U3. ETI owns a 1038 ETI Ex. 28 (Mcllvoy Direct) at 5-6. 1039 ETI Ex. 34 (Cooper Direct) at 6-10. 1040 ETI Ex. 40 (Thiry Direct) at 24. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE326 PUC DOCKET NO. 39896 29.75 percent interest in Nelson 6 and operates the unit. ETI owns a 17.85 percent interest in BCWU3, 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 BCWU3, 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 witrtess 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 1041 Id. 1042 ETI Ex. 33 (Trushenski Direct) at 2. 1043 Id. at 11-13. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE327 PUC DOCKET NO. 39896 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 reliable and flexible gas supply over the same period. 1044 fu Section V .H., above, the AU s 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 AUs 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. fu 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 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 N O . - PROPOSAL FOR DECISION PAGE328 PUC DOCKET NO. 39896 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 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 AUs 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 AUs, therefore, recommend that the Commission reject the Cities' proposed adjustment. C. ETl'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 1049 P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added). 1050 ETI Ex. 23 (Zakrzewski Direct) at 13. 1051 Id. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE329 PUC DOCKET NO. 39896 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 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)(l), 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 1052 Cities Initial Brief at 86. 1053 ETI Reply Brief at 93. 1054 ETI Ex. 42 (Lewis Supplemental Direct) at 5.  ""--~·-···--··--------------------------- SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE330 PUC DOCKET NO. 39896 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 .... " 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, ifETI'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 AU s 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 ALls do 1055 ETI Ex. 42 (Lewis Supplemental Direct) at 4 and Adjustment No. 16.L. SOAHDOCKETNO.- PROPOSAL FOR DEQSION PAGE331 PUC DOCKET NO. 39896 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. 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§§ 36.051and36.003(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 ETl-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 31.00l(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 31.00l(c). More specifically, ETI stated, bothRTO membership and deferred accounting itself constitute examples of policies required by section 31.00l(c) to support wholesale competition. Therefore, ETI argues that its request for deferred 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.3dat723. SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE332 PUC DOCKET NO. 39896 accounting should be approved because it is necessary to carry out PURA§§ 36.051, 36.003, and 31.00l(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. 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 31.00l(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 proposaI. 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 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. 1062 883 S.W.2d 190 (Tex. 1994). 1063 TIEC Ex. 1 (Pollock Direct) at 46-47. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE333 PUC DOCKET NO. 39896 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 l percent of ETI's Test Year operating revenues, according to Mr. Pollock. In his opinion, this level of MISO 1065 transition costs is easily subsumed in the normal variation in ETI's year-to-year expenses. 1066 TIEC also disagreed with ETI's interpretation of State v. Public Utility Comm'n ofTexas. 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 Hammack 1067 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 1064 ETI Ex. 42 (Lewis Supplemental Direct) at 5. 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, 131S.W.3d713, 724 (Tex .App.-Austin 2004, pet. denied). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE334 PUC DOCKET NO. 39896 circumstances." 1070 Rather, Staff stated, the Commission merely declined to designate a specific standard. Staff also rejected ETI' s argument that deferred accounting will "ensure that the Commission meets its obligation under Section 31.00 l (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. ion 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 accOlmting is necessary to cairy 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 ofTexas 1013 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 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). 1071 ETI Initial Brief at 234. 1072 Docket No. 39741, Preliminary Order at 11. 1073 883 S.W.2d 190 (Tex. 1994). SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE335 PUC DOCKET NO. 39896 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. As for Staff and TIEC's argument that deferred accounting is not necessary to carry out PURA§ 31.00l(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 carryout Section 31.00l(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 ALls conclude that ETI has not shown that it is necessary to carry out a provision of PURA. The AU s 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 1074 ETI Reply Brief at 95-96. 1075 Docket No. 397 41, 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 N O . - PROPOSAL FOR DECISION PAGE336 PUC DOCKET NO. 39896 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 ALls 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 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, 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 N O . - PROPOSAL FOR DECISION PAGE337 PUC DOCKET NO. 39896 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, 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 AU s 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§§ 36.051and36.003(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 ALls recommend that the SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE338 PUC DOCKET NO. 39896 Commission deny ETI' s request for deferred accounting treatment of its MISO transition expenses to be incurred on or after January 1, 2011. 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' sown 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 t0s 3 883 S.W.2d 190, 196 (Tex. 1994). 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 N O . - PROPOSAL FOR DECISION PAGE339 PUC DOCKET NO. 39896 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 concluded that ETI' s share of future MISO transition costs cannot be appropriately measured. toss 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. to86 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 annual basis. Furthermore, ETI' s expects $17 million in transition expenses to be incurred over three years, which equates to $5.8 million annually. 1089 lnETI's view, the issue is whether it is sufficiently known that ETI will incur at least $12 million in transition expense, not whether ETI can predict an exact level of future expense. 1090 The AUs recommend that the Commission authorize ETI to include $2.4 million in base rates set in the present case for MISO transition expense incurred on or after January 2, 2011, based on a five-year amortization of $12 million in total projected expenses. The primary argument of intervenors against the adjustment is that the total of $12 million is not a known and measurable change. However, the AUs find that ETI's evidence established that such expenses will total at least $12 million. It is true that the Test Year expenses were less, but ETI filed its application to effectuate the transfer to MISO in 2012, so it is clear that those expenses will increase significantly 1085 TIEC Ex. 1 (Pollock Direct) at 49-50. 1086 TIEC Initial Brief at 97-98; TIEC Reply Brief at 70-71. 1087 Staff Reply Brief at 65-66. 1088 ETI Ex. 46 (Considine Rebuttal), Ex. MPC-R-1. 1089 TIEC Ex. 1 (Pollock Direct) at 48:3-4. 1090 ETI Initial Brief at 236-239; ETI Reply Brief at 99-100. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE340 PUC DOCKET NO. 39896 to levels well above the Test Year amount. It is true that ETI has not established the precise total amount of MISO transition expenses it will incur, but the ALJs find that those expenses will likely exceed the $12 million included in ETI's request. ETI requested that the $12 million total be amortized over three years, which would produce a $4 million annual cost. However, ETI also requested to amortize over five years its $263,908 in MISO transition expenses that were incurred during the 2010 portion of the Test Year ($52,800 per year). If a five-year amortization is appropriate for those expenses, a five-year amortization would also be appropriate for the post Test Year MISO transition expenses. Therefore, the ALJs recommend that the Commission authorize ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of the Test Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of $2,452,800. B. TCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2] In its Supplemental Preliminary Order, the Commission found that it would be appropriate to establish for ETI baseline values for a TCRF and a DCRF, which may be established in future dockets. ETI' s filing package included worksheets for these baseline values, 1091 and ETI attached revised versions of the worksheets to its initial brief to reflect ETI' s revised depreciation calculations. The revised version of the transmission worksheet calculated total transmission cost baseline revenue requirements of $75,074,987-Total Company and $74,997,366-Retail. 1092 However, ETI acknowledged that these values may change, depending on the rulings in this case. If the Commission makes other changes to ETI' s requested costs, ETI proposes filing another revised TCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions of the Commission. 1093 TIEC, Cities, and Staff also point out that various items in ETI's calculation have been contested. Therefore, they also recommend that the baseline values be set during the compliance phase of this case. The ALJ s agree that TCRF baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation. 1091 ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6. 1092 ETI Initial Brief at 239 and Attachment 1. 1093 ETI Initial Brief at 239. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE341 PUC DOCKET NO. 39896 C. DCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2] As discussed above, the Commission found in its Supplemental Preliminary Order that it would be appropriate to establish for ETI baseline values for a DCRF, which may be established in a future docket. ETI' s filing package included worksheets for a DCRF baseline value, 1094 and ETI attached a revised version of the worksheet to its initial brief to reflect ETI' s revised depreciation calculations. The revised version of the distribution worksheet calculated total distribution cost baseline revenue requirements of $163,560,232-Total Company and $161,537,490-Retail. 1095 However, ETI acknowledged that these values may change, depending on the rulings in this case. If the Commission makes other changes to ETI' s requested costs, ETI proposes filing another revised DCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions of the Commission. 1096 TIEC, Cities, and Staff also recommend that the baseline values be set during the compliance phase of this case. The ALl s agree that DCRF baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation. D. Purchased Power Capacity Cost Baseline [Germane to Supplemental Preliminary Order Issue No. 1] ETI requested a PPR rider in its application, but the Commission held in its Supplemental Preliminary Order that the proposed rider should not be considered due to the pending rulemaking Project No. 39246, which was opened to consider purchased capacity riders. However, the Commission did add the following issue to the present case: "What is the amount of purchased- capacity costs that are proposed to be included in Entergy' s base rates?" ETI requested authority to include $275,809,485 in its PPR rider, but because the Commission excluded the PPR rider from consideration, this amount would now be included in base rates. ETI acknowledged that this amount 1094 ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6. 1095 ETI Initial Brief at 239 and Attachment 2. 1096 ETI Initial Brief at 239. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE342 PUC DOCKET NO. 39896 should be revised to correspond with the Commission's final decision on purchased power capacity 1097 recovery (See Section VII.A.). State Agencies noted that ETI' s purchased power request included the following: 1. Third-party contracts; 2. Legacy affiliate contracts; 3. Other affiliate contracts; and 4. Reserve Equalization. The costs for all of these but third-party contracts are determined through various MSS Schedules in the FERC-approved Entergy System Agreement. Therefore, State Agencies argue that if the Commission decides to allow purchased capacity cost recovery riders in Project No. 39246, the baseline costs for ETI should be limited to only the purchased capacity costs associated with non-affiliate third-party contracts. In State Agencies' opinion, ETI should not be allowed to pass through purchased capacity costs associated with legacy and other affiliate contracts or reserve equalization purchases, because those are not market competitive contracts. Instead, according to State Agencies, the affiliate contracts and reserve equalization purchases are essentially agreements to share centralized planned generation capacity resources among Entergy Operating Companies and to allocate generation costs among those companies. State Agencies also noted that these capacity payments are determined based on formulae in Service Schedules MSS-1 and MSS-4, included in the FERC-approved Entergy System Agreement. In other words, these costs are not driven by market prices and are not subject to market price volatility. Therefore, State Agencies argue that purchases other than third-party contracts should not be used as a baseline for any rider intended to address market price volatility and competitive wholesale market pressure for purchased generation . • 1098 capacities. 1097 ETI Initial Brief at 240. 1098 State Agencies Ex. 2 (Pevoto Direct) at 17. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE343 PUC DOCKET NO. 39896 Cities agree with the arguments of State Agencies. fu addition, Cities stressed that if the Commission establishes a baseline for purchased power capacity costs, the baseline should reflect the unit cost of capacity rather than total dollars. Cities witness Nalepa testified that the unit cost would provide a more accurate measure than total dollars. fu Cities• opinion, if a unit cost finding is not made in this case, then Commission will be prevented from considering all options in the rulemak:ing. TIEC points out that the notice in Project No. 39246 provided that "[t]he purpose of this rulemak:ing project is to address the recovery of purchased power capacity costs considering generation embedded in base rates, load growth, and the impact of purchased power capacity recovery on the financial standing of the utility." 1099 Accordingly, TIEC argues that the baseline set in this proceeding should reflect ETI' s total purchased power and installed capacity costs determined to be properly included in base rates on a total cost basis and on a per unit ($/MW) basis. 1100 As discussed in Section VII.A., the ALJ s find that the appropriate amount for ETI' s purchased power capacity expense to be included in base rates is $245,432,884. This responds to the issue included in the Commission's Supplemental Preliminary Order. This amount includes third- party contracts, legacy affiliate contracts; other affiliate contracts; and reserve equalization. Whether the amounts for all contracts should be included in the baseline for a purchased capacity rider that may be approved in Project No. 39246 is an issue that should be decided in that proceeding, not in the present case. Therefore, the ALJ s make no recommendation on that issue raised by the intervenors. XIII. CONCLUSION The AUs recommend that the Commission implement the findings of the AUs set forth in the discussion above by adopting the following proposed findings of fact and conclusions of law in the Commission's final order. 1099 Project No. 39246, Public Notice (May 10, 2011). 1100 TIEC Initial Brief at 99. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE344 PUC DOCKET NO. 39896 XIV. PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND ORDERING PARAGRAPHS A. Findings of Fact Procedural History 1. Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail service area located in southeastern Texas. 2. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI served approximately 412,000 Texas retail customers. The Federal Energy Regulatory Commission (FERC) regulates ETI's wholesale electric operations. 3. On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed increase in annual base rate revenues of approximately $111.8 million over adjusted test year revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying ETI' s application and including new riders for recovery of costs related to purchased power capacity and renewable energy credit requirements; (3) a request for final reconciliation of ETI's fuel and purchased power costs for the reconciliation period from July 1, 2009 to June 30, 2011; and (4) certain waivers to the instructions in RFP Schedule V accompanying ETI' s application. 4. The 12-month test year employed in ETI's filing ended on June 30, 2011 (Test Year). 5. ETI provided notice by publication for four consecutive weeks before the effective date of the proposed rate change in newspapers having general circulation in each county of ETI' s Texas service territory. ETI also mailed notice of its proposed rate change to all of its customers. Additionally, ETI timely served notice of its statement of intent to change rates on all municipalities retaining original jurisdiction over its rates and services. 6. The following parties were granted intervenor status in this docket: Office of Public Utility Counsel (OPC); the 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 (Cities), the Kroger Co. (Kroger); State Agencies (State Agencies); Texas Industrial Energy Consumers (TIEC); East Texas Electric Cooperative, Inc. (ETEC); the United States Department of Energy (DOE); and Wal-Mart Stores Texas, LLC, and Sam's East, Inc. (Wal Mart). The Staff (Staff) of the Public Utility Commission of Texas (Commission or PUC) was also a participant in this docket. 7. On November 29, 2011, the Commission referred this case to the State Office of Administrative Hearings (SOAH). SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE345 PUC DOCKET NO. 39896 8. On December 7, 2011, the Commission issued its order requesting briefing on threshold legal/policy issues. 9. On December 19, 2011, the Commission issued its Preliminary Order, identifying 31 issues to be addressed in this proceeding. 10. On December 20, 2011, the Administrative Law Judges (AUs) issued SOAH Order No. 2, which approved an agreement among the parties to establish a June 30, 2012 effective date for the Company's new rates resulting from this case pursuant to certain agreed language and consolidate Application of Entergy Texas, Inc. for Authority 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 13, 2012, the AU s 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 participate as counsel for Wal-Mart. 12. On January 19, 2012, 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 Commission petitions for review of the rate ordinances of the municipalities exercising original jurisdiction within its service territory. All such appeals were consolidated for determination in this proceeding. 14. OnApril4, 2012, theAUs issued SOAH Order No. 13 severingratecaseexpenseissues into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from 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. 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. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE346 PUC DOCKET NO. 39896 19. ETI's proposed Hurricane Rita regulatory asset was an issue resolved 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 amortization 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 CWIP in rate base, and there was insufficient evidence showing that major projects under construction were efficiently and prudently managed. 27. The portion of the Prepaid Pension Assets Balance that is capitalized to CWIP should not be included in ETI' s rate base. 28. The remainder of the Prepaid Pension Assets Balance should be included in ETI' s rate base. 29. ETI should be permitted to accrue an allowance for funds used during construction on the portion ofETI's Prepaid Pension Assets Balance capitalized to CWIP. 30. The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48 (FIN 48), "Accountingfor Uncertainty in Income Taxes," requires ETI to identify each of its uncertain tax positions by evaluating the tax 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. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE347 PUC DOCKET NO. 39896 31. FIN 48 requires ETI to remove the amount of its uncertain 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 has, 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 the IRS. 33. ETI has deposited $1,294,683 with the IRS in connection with the FIN 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. 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 IRS for the FIN 48 Liability) should be added to ETI' s AD FIT and thus be used to reduce ETI' s rate base. 40. ETI's application and proposed tariffs do not include a request for a tracking mechanism or rider to collect a return on the FIN 48 Liability. 41. ETI has not proven that a tracking mechanism or rider to collect a return on FIN 48 Liability is necessary. 42. Investor-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 amount of working capital, not specifically addressed 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 isconsistentwithP.U.C. SUBST. R. 25.231(c)(2)(B)(iii). SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE348 PUC DOCKET NO. 39896 45. It is reasonable to establish ETI' s cash working capital requirement based on ETI' s lead-lag study as updated in Jay 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 primafacie case concerning the prudence of its storm 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 storm reserve balance was negative $59,799,744. 51. The amount of $9,846,037, representing the value of the average coal inventory maintained at ETI' 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 far 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-term assets to the 13-month period ending December 2011, which was the most recent information available. Staff's 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. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE349 PUC DOCKET NO. 39896 58. ETI' s $1, 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 payments made by ETI for incentive compensation tied to financial goals. 61. The portion of ETI' s incentive payments that are capitalized and that are financially-based should be excluded from ETI' s rate base because the benefits of such payments inure most immediately and predominantly to ETI's shareholders, rather than its electric customers. 62. The Test Year for ETI's prior ratemaking proceeding ended on June 30, 2009, and the reasonableness of ETI' s capital cos ts (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-based should be excluded from rate base, but only for incentive costs that ETI capitalized during the period from July 1, 2009 (the endofthepriorTest Year)throughJune30, 2010 (the commencement of the current Test Year). Rate of Return 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. 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. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE350 PUC DOCKET NO. 39896 71. ETI's overall rate ofreturn should be set as follows: CAPITAL WEIGHTED A VG COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL LONG· TERM DEBT 50.08% 6.74% 3.38% COMMON EQUITY 49.92% 9.80% 4.89% TOTAL 100.00% 8.27% Operating Expenses 72. ETI's Test Year purchased capacity expenses were $245.432,884. 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). 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 ETI 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 under the contract, even though that assumption is inconsistent with ETI' s historical experience. 78. There is substantial uncertainty with regard to ETI' s projection of its Rate Year third-party capacity contract payments. 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. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE351 PUC DOCKET NO. 39896 81. Over $11 million ofETI's affiliate transactions were basedona2013 contract(theEAIWBL Contract) that was not signed until April 11, 2012. 82. There is uncertainty about whether the EAI WBL Contract will ever go into effect. 83. ETI projects purchasing over 300 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. 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 ,432,884. 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. ETI'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. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE352 PUC DOCKET NO. 39896 94. ETI' s transmission equalization expense in this case should be based on the Test Year level of $1,753,797. 95. P.U.C. SUBST. R. 25.231(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 amortization 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. 101. 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 transm1ss10n 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 ETI'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. 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. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE353 PUC DOCKET NO. 39896 107. A service life of 65 years and a dispersion curve of R3 for ETI' s distribution structures and improvements (FERC Account 361) are the 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 ETI's 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 ofL4 for ETI' s distribution overhead service (FERC Account 369.1) are the most reasonable of those proposed and should be approved. 113. 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. 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 salvage rate of negative 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 10 percent for ETI' s distribution overhead services (FERC Account 369.1) is the most reasonable of those proposed and should be adopted. 118. The net salvage rate of negative 10 percent for ETI'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 ETI's general structures and improvements (FERC Account 390) are the most reasonable of those proposed and should be approved. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE354 PUC DOCKET NO. 39896 120. The net salvage rate of negative 10 percent for ETI's general structures and improvements (FERC Account 390) is the most reasonable of those proposed and should be adopted. 121. It is reasonable to convert 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 life analysis determined that a five-year life was appropriate for general plant computer equipment (FERC Account 390.2). 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. In 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 counting of three ETI and one ESI employee; (b) 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) payroll 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, annual 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 predominant 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.  ~~···--····-------------------------- SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE355 PUC DOCKET NO. 39896 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 Exeeutive 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. 134. The amount of incentive compensation that should be included in the cost of service is $7,991,707. 135. To attract and retain highly qualified employees, the Entergy Companies provide a total package of compensation and benefits that is equivalent in scope and cost with what other comparable companies within the utility business and other industries provide for their employees. 136. When using a benchmark analysis to compare companies' levels of compensation, it is reasonable to view the market level of compensation as a range rather than a precise, single point. 137. ETI's base pay levels are at market. 138. ETI' s benefits plan levels are within a reasonable range of market levels. 139. ETI's level of compensation and benefits expense is reasonable and necessary. 140. ETI provides non-qualified supplemental executive retirement plans for highly compensated individuals such as key managerial employees and executives that, because of limitations imposed under the Internal Revenue Code, would otherwise not receive retirement benefits on their annual compensation over $245,000 per year. 141. ETI' s non-qualified supplemental executive retirement plans are discretionary costs designed to attract, retain, and reward highly compensated employees whose interests are more closely aligned with those of the shareholders than the customers. 142. ETI's non-qualified executive retirement benefits in the amount of $2,114,931 are not reasonable or necessary to provide utility service to the public, not in the public interest, and should not be included in ETI' s cost of service. 143. For the employee market in which ETI operates, most peer companies offer moving assistance. Such assistance is expected by employees, and ETI would be placed at a competitive disadvantage if it did not offer relocation expenses. 144. ETI's relocation expenses were reasonable and necessary. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE356 PUC DOCKET NO. 398% 145. The Company's requested operating expenses should be reduced by $40,620 to reflect the removal of certain executive prerequisites proposed by Staff. 146. Staff properly adjusted the Company's requested interest expense of $68,985 by removing $25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year 2012), leaving a recommended interest expense of $43,047. 147. During the Test Year, ETI's property tax expense equaled $23,708,829. 148. ETI requested an upward proforma adjustment of $2,592,420, to account for the property tax expenses ETI estimates it will pay in the Rate Year. 149. ETI' s requested proforma adjustment is not reasonable because it is based, in part, upon the prediction that ETI' s property tax rate will be increased in 2012, a change that is speculative is not known and measurable. 150. Staff's recommendation to increase ETI's Test Year property tax expenses by $1,214,688 is based on the historical effective tax rate applied to the known Test Year-end plant in service value, consistent with Commission precedent, and based upon known and measurable changes. 151. ETI's Test Year property tax burden should be adjusted upward by $1,214,688. 152. Staff recommended reducing ETI's advertising, dues, and contributions expenses by $12,800. The recommendation, which no party contested, should be adopted. 153. The final cost of service should reflect changes to cost of service that affect other components of the revenue requirement such as the calculation of the Texas state gross receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible Expenses. 154. The Company's requested Federal income tax expense is reasonable and necessary. 155. ETI's request for $2,019,000 to be included in its cost of service to account for the Company's annual decommissioning expenses associated with River Bend is not reasonable because it is not based upon "the most current information reasonably available regarding the cost of decommissioning" as required by P.U.C. SUBST. R. 25.23l(b)(l)(F)(i). 156. Based on the most current information reasonably available, the appropriate level of decommissioning costs to be included in ETI's cost of service is $1,126,000. 157. ETI's appropriate total annual self-insurance storm damage reserve expense is $8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its current deficit. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE357 PUC DOCKET NO. 39896 158. ETI's appropriate target self-insurance storm damage reserve is $17,595,000. 159. ETI should continue recording its annual storm damage reserve accrual until modified by a Commission order. 160. The operating costs of the Spindletop Facility are reasonable and necessary. 161. The operating costs of the Spindletop Facility paid to PB Energy Storage Services are eligible fuel expenses. Affiliate Transactions 162. ETI affiliates charged ETI $78,998,777 for services during the Test Year. The majority of these O&M expenses-$69,098,041-were charged to ETI by ESL The remaining affiliate services were charged (or credited) to ETI by: Entergy Gulf States Louisiana, L.L.C.; Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.; Entergy Operations, Inc.; and non-regulated affiliates. 163. ESI follows a number of processes to ensure that affiliate charges are reasonable and neces'sary and that ETI and its affiliates are charged the same rate for similar services. These processes include: (a) the use of service agreements to define the level of service required and the cost of those services; (b) direct billing of affiliate expenses where possible; (c) reasonable allocation methodologies for costs that cannot be directly billed; (d) budgeting processes and controls to provide budgeted costs that are reasonable and necessary to ensure appropriate levels of service to its customers; and (e) oversight controls by ETI's Affiliate Accounting and Allocations Department. 164. Affiliates charged expenses to ETI through 1292 project codes during the Test Year. 165. ETI agreed to remove the following affiliate transactions from its application: (1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553; (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288; and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929. 166. The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated with Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non Qual Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the provision of electric utility service and are not in the public interest. 167. The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts Settlement) are not normally-recurring costs and should not be recoverable. 168. The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are related to ESI's operations, it is more immediately related to Entergy Louisiana, Inc. and Entergy New Orleans, Inc. As such, they are not recoverable from Texas ratepayers. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE358 PUC DOCKET NO. 39896 169. The $171,032 of costs associated with Project F3PPE9981 S (futegrated Energy Management for ESI) are research and development costs related to energy efficiency programs. As such, they should be recovered through the energy efficiency cost recovery factor rather than base rates. 170. Except as noted in the above Findings of Fact Nos. 162-169, all remaining affiliate transactions were reasonable and necessary, were allowable, were charged to ETI at a price no higher than was charged by the supplying affiliate to other affiliates, and the rate charged is a reasonable approximation of the cost of providing service. Jurisdictional Cost Allocation 171. ETI has one full or partial requirements wholesale customer - East Texas Electric Cooperative, fuc. 172. ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set the wholesale load results in a retail production demand allocation factor of 95.3838 percent. 173. The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used by the FERC to allocate between jurisdictions. 174. Using 12CP methodology to allocate production costs between the wholesale and retail jurisdictions is the best method to reflect cost responsibility and is appropriate based on ETI's reliance on capacity purchases. Class Cost Allocation and Rate Design 17 5. There is no express statutory authorization for ETI' s proposed Renewable Energy Credits Rider (REC Rider). 176. REC Rider constitutes improper piecemeal ratemaking and should be rejected. 177. ETI' s Test Year expense for renewable energy credits, $623,303, is reasonable and necessary and should be included in base rates. 178. Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use public rights-of-way to locate its facilities within municipal limits. 179. ETI is an integrated utility system. ETI' s facilities located within municipal limits benefit all customers, whether the customers are located inside or outside of the municipal limits. 180. Because all customers benefit from ETI's rental of municipal right-of-way, municipal franchise fees should be charged to all customers in ETI' s service area, regardless of geographic location. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE359 PUC DOCKET NO. 39896 181. It is reasonable and consistent with the Public Utility Regulatory Act (PURA)§ 33.008(b) that MFF be allocated to each customer class on the basis of in-city kilo-watt hour (kWH) sales, without an adjustment for the MFF rate in the municipality in which a givenkWH sale occurred. 182. The same reasons for allocating and collecting MFF as set out in Finding of Fact Nos. 178- 181 also apply to the allocation and collection of Miscellaneous Gross Receipts Taxes. The Company's proposed allocation of these costs to all retail customer classes based on customer class revenues relative to total revenues is appropriate. 183. The Average and Excess (A&E) 4CP method for allocating capacity-related production costs, including reserve equalization payments, to the retail classes is a standard methodology and the most reasonable methodology. 184. The A&E 4CP method for allocating transmission costs to the retail classes is standard and the most reasonable methodology. 185. ETI appropriately followed the rate class revenue requirements from its cost of service study to allocate costs among customer classes. ETI' s revenue allocation properly sets rates at each class's cost of service. 186. It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any replacement of a functioning light with a lower-wattage bulb. 187. It is appropriate to require ETI to prepare and file, as part of its next base rate case, a study regarding the feasibility of instituting LED-based rates and, if the study shows that such rates are feasible, ETI should file proposals for LED-based lighting and traffic signal rates it next rate case. 188. An agreement was reached by the parties and approved by the Commission in Docket No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand ratchet for existing customers in the Large Industrial Power Service (LIPS), Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day, Large General Service, and Large General Service-Time of Day rate schedules. 189. ETl's proposed tariffs in this case did not remove the life-of-contract demand ratchet from these rate schedules consistent with the parties' agreement in Docket No. 37744. 190. A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI proposed, is not reasonable. 191. ETI's proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the agreement that was adopted by the Commission as just and reasonable in Docket No. 37744. Accordingly, these tariffs should be modified as set out in Findings of Fact No. 192-194. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE360 PUC DOCKET NO. 39896 192. ETI' s Schedule LIPS and LIPS Time of Day § VI should be changed to read: DETERMINATION OF BILLING LOAD The kW of Billing Load will be the greatest of the following: (A) The Customer's maximum measured 30-minute demand during any 30-minute interval of the current billing month, subject to§§ III, IV and V above; or (B) 60% of Contract Power as defined in § VII; or (C) 2,500 kW. 193. ETI' s Schedule LIPS and LIPS Time of Day § VII should be changed to read: DETERMINATION OF CONTRACT POWER Unless Company gives customer written notice to the contrary, Contract Power will be defined as below: Contract Power - the highest load established under § Vl(A) above during the 12 months ending with the current month. For the initial 12 months of Customer's service under the currently effective contract, the Contract Power shall be the kW specified in the currently effective contract unless exceeded in any month during the initial 12-month period. 194. The Large General Service and Large General Service-Time of Day schedules should be similarly revised to eliminate ETI's life-of-contract demand ratchet. 195. In its proposed rate design for the LIPS class, the Company took a conservative approach and increased the current rates by an equal percentage. This minimized customer bill impacts while maintaining cost causation principles on a rate class basis. 196. It is a reasonable move towards cost of service to add a customer charge of $630 to the LIPS rate schedule with subsequent increases to be considered in subsequent base rate cases. 197. It is a reasonable move towards cost of service to slightly decrease the LIPS energy charges and increase the demand charges as proposed by Staff witness William B. Abbott. 198. DOE proposed a new Schedule LIPS rider-Schedule "Schedulable Intermittent Pumping Service" (SIPS) for load schedulable at least four weeks in advance, that occurs in the off- SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE361 PUC DOCKET NO. 39896 season (November through April), that can be cancelled at any time, and for load not lasting more than 80 hours in a year. For customers whose loads match these SIPS characteristics (for example, DOE's Strategic Petroleum Reserve), the 12-month demand ratchet provision of Schedule LIPS does not apply to demands set under the provisions of the SIPS rider. The monthly demand set under the SIPS provisions would be applicable for billing purposes only in the month in which it occurred. In short, if a customer set a 12-month ratchet demand in that month, it would be forgiven and not applicable in the succeeding 12 months. 199. DOE' s proposed Schedule SIPS is not restricted solely to the DOE and should be adopted. It more closely addresses specific customer characteristics and provides for cost-based rates, as does another ETI rider applicable to Pipeline Pumping Service. 200. Standby Maintenance Service (SMS) is available to customers who have their own generation equipment and who contract for this service from ETI. 201. P.U.C. SUBST. R. 25.242(k)(l) provides that rates for sales of standby and maintenance power to qualifying facilities should recognize system wide costing principles and should not be discriminatory. 202. It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer charge equivalent to that of the LIPS rate schedule only for SMS customers not purchasing supplementary power under another applicable rate; and (b) revising the tariff as follows: Distribution Transmission Charge (less than 69KV) (69KV and greater) Billing Load Charge ($/kW): Standby $2.46 $0.79 Maintenance $2.27 $0.60 Non-Fuel Enernv Charge (¢/kWh) On-Peak 0.881¢ 0.846¢ Off-Peak 0.575¢ 0.552¢ 203. ETI's Additional Facilities Charge Rider (Schedule AFC) prescribes the monthly rental charge paid by a customer when ETI installs facilities for that customer that would not normally be supplied, such as line extensions, transformers, or dual feeds. 204. ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge. Option B, which applies when a customer elects to amortize the directly-assigned facilities over a shorter term ranging from one to ten years, has a variable monthly charge. There is also a term charge that applies after the facility has been fully depreciated. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE362 PUC DOCKET NO. 39896 205. It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.20 percent per month of the installed cost of all facilities included in the agreement for additional facilities. 206. It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and the Post Term Recovery Charge as follows: Selected Recovery Term Recovery Term Charge Post Recovery Term Charge 1 10.88% 0.35% 2 5.39% 0.35% 3 3.92% 0.35% 4 ' 3.20% 0.35% 5 2.76% 0.35% 6 2.48% 0.35% 7 2.28% 0.35% 8 2.14% 0.35% 9 1.97% 0.35% 10 1.94% 0.35% 207. The revisions in the above Findings of Fact to Schedule AFC rates reasonably reflect the costs of running, operating, and maintaining the directly-assigned facilities. 208. It is reasonable to modify the Large General Service rate schedule by increasing the demand charge from $10.25 to $12.81; decreasing the energy charge from $.01023 to $.00513; and maintaining the customer charge at $425.05. 209. Staffs proposed change to the General Service (GS) rate schedule to gradually move GS customers towards their cost of service by recommending a decrease in the customer charge from the current rate of $41.09 to $39.91, and a decrease in the energy charges is reasonable and should be adopted. 210. ETI's Residential Service (RS) rate schedule is composed of two elements: a customer charge of $5 per month and a consumption-based energy charge. The Energy charge is a fixed rate of 5.802¢ per kWh from May through October (Summer). In the months November through April (Winter), the rates are structured as a declining block, in which the price of each unit is reduced after a defined level of usage. 211. ETI' s Schedule RS declining block rate structure is contrary to energy efficiency efforts and the Legislature's goal of reducing both energy demand and energy consumption in Texas, as stated in PURA§ 39.905. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE363 PUC DOCKET NO. 39896 212. Schedule RS winter block rates should be modified consistent with the goal set out in PURA § 39.905, with the initial phase-in of a 20 percent reduction in the block differential proposed by ETI and subsequent reductions should be reviewed for consideration at the occurrence of each rate case filing. 213. Other elements of Schedule RS are just and reasonable. Fuel Reconciliation 214. ETI incurred $616,248,686 in natural-gas expenses during the Reconciliation Period, which is from July 2009 through June 2011. 215. ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and negotiated operational balancing agreements with various pipeline companies. 216. ETI employed a diversified portfolio of gas supply and transportation agreements to meet its natural-gas requirements, and ETI prudently managed its gas-supply contracts. 217. ETI's natural gas expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers. 218. ETI incurred $90,821,317 in coal expenses during the Reconciliation Period. 219. ETI prudently managed its coal and coal-related contracts during the Reconciliation Period. 220. ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal burned at the Big Cajun II, Unit 3 facility. 221. ETI's coal expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers. 222. ETI incurred $990,041,434 in purchased-energy expenses during the Reconciliation Period. 223. The Entergy System's planning and procurement processes for purchased power produced a reasonable mix of purchased resources at a reasonable price. 224. During the Reconciliation Period, ETI took advantage of opportunities in the fuel and purchased-power markets to reduce costs and to mitigate against price volatility. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE364 PUC DOCKET NO. 39896 225. ETI's purchased-energy expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers. 226. ETI provided sufficient contemporaneous documentation to support the reasonableness of its purchased-power planning and procurement processes and its actual power purchases during the Reconciliation Period. 227. The Entergy system sold power off system when the revenues were expected to be more than the incremental cost of supplying generation for the sale, subject to maintaining adequate reserves. 228. The System Agreement is the tariff approved by the FERC that provides the basis for the operation and planning of the Entergy system, including the six Operating Companies. The System Agreement governs the wholesale-power transactions among the Operating Companies by providing for joint operation and establishing the bases for equalization among the Operating Companies, including the costs associated with the construction, ownership, and operation of the Entergy system facilities. 229. Under the terms of the Entergy System Agreement, ETI was allocated its share of revenues and expenses from off-system sales. 230. During the Reconciliation Period, ETI recorded off-system sales revenue in the amount of $376,671,969 in FERC Account 447 and credited 100 percent of off-system sales revenues and margins from off-system sales to eligible fuel expenses. 231. ETI properly recorded revenues from off-system sales and credited those revenues to eligible fuel costs. 232. The Entergy system consists of six Operating Companies, including ETI, which are planned and operated as a single, integrated electric system under the terms of the System Agreement. 233. Service Schedule MSS-1 of the System Agreement determines how the capability and ownership costs of reserves for the Entergy system are equalized among the Operating Companies. These inter-system "reserve equalization" payments are the result of a formula rate related to the Entergy system's reserve capability that is applied on a monthly basis. 234. Reserve capability under Service Schedule MSS-1 is capability in excess of the Entergy system's actual or planned load built or acquired to ensure the reliable, efficient operation of the electric system. SOAHDOCKETNO.- PROPOSAL FOR DECISION PAGE365 PUC DOCKET NO. 39896 235. By approving Service Schedule MSS-1, the FERC has approved the method by which the Operating Companies share the cost of maintaining sufficient reserves to provide reliability for the Entergy system as a whole. 236. Service Schedule MSS-3 of the System Agreement determines the pricing and exchange of energy among the Operating Companies. By approving Service Schedule MSS-3, the FERC has approved the method by which the Operating Companies are reimbursed for energy sold to the exchange energy pool and how that energy is purchased. 237. Service Schedule MSS-4 of the System Agreement sets forth the method for determining the payment for unit power purchases between Operating Companies. By approving Service Schedule MSS-4, the FERC has approved the methodology for pricing Inter-Operating Company unit power purchases. 238. The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day horizons. Once the planning process has identified the most economical resources that can be used to reliably meet the aggregate Entergy system demand, the next step is to procure the fuel necessary to operate the generating units as planned and acquire wholesale power from the market. 239. Once resources are procured to meet forecasted load, the Entergy system is operated during the current day using all the resources available to meet the total Entergy system demand. 240. After current-day operation, the System Agreement prescribes an accounting protocol to bill the costs of operating the system to the individual Operating Companies. This protocol is implemented via the Intra-System Bill (ISB) to each Operating Company on a monthly basis. 241. ETI purchased power from affiliated Operating Companies per the terms of Service Schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3 to affiliated Operating Companies are reasonable and necessary, and the FERC has approved the pricing formula and the obligation to purchase the energy. ETI pays the same price per megawatt hour for energy under Service Schedule MSS-3 as does any other Operating Company purchasing energy under Service Schedule MSS-3 during the same hour. 242. The Spindletop Facility is used primarily to ensure gas-supply reliability and guard against gas-supply curtailments that can occur as a result of extreme weather or other unusual events. 243. The Spindletop Facility provides a secondary benefit of flexibility in gas supply. ETI can back down gas-fired generation to take advantage of more economical wholesale power, or use gas from storage to supplement gas-fired generation when load increases during the day and thereby avoid more expensive intra-day gas purchases. SOAHDOCKET N O . - PROPOSAL FOR DECISION PAGE366 PUC DOCKET NO. 39896 244. ETI' s customers received benefits from the Spindletop Facility during the Reconciliation Period through reliable gas supplies and ETI's monthly and daily storage activity. 245. ETI prudently managed the Spindletop Facility to provide reliability and flexibility of gas supply for the benefit of customers. 246. ETI proposed new loss factors, based on a December 2010 line loss study, to be applied for the purpose of allocating its costs to its wholesale customers and retail customer classes. 247. ETI's proposed loss factors are reasonable and shall be implemented on a prospective basis as a result of this final order. 248. ETI seeks a special-circumstances exception to recover $99,715 resulting from the FERC's reallocation of rough production equalization costs in FERC Order No. 720-A, and to treat such costs as eligible fuel expense. 249. Special circumstances exist and it is appropriate for recovery of the rough production cost equalization costs reallocated to ETI as a result of the FERC' s decision in Order No. 720-A. Other Issues 250. A deferred accounting of ETI' s Midwest Independent Transmission System Operator (MISO) transition expenses is not necessary to carry out any requirement of PURA. 251. ETI should include $2.4 million in base rates for MISO transition expense incurred on or after January 2, 2011, based on a five-year amortization of $12 million in total projected expenses. 252. ETI should include an additional $52,800 in base rates for MISO transition expenses incurred during the 2010 portion of the Test Year, based on a five-year amortization of $263,908 in such expenses. 253. Transmission Cost Recovery Factor baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation. 254. Distribution Cost Recovery Factor baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE367 PUC DOCKET NO. 39896 25 5. The appropriate amount for ETI' s purchased power capacity expense to be included in base rates is $245,432,884. 256. The amount of ETI's purchased power capacity expense includes third-party contracts, legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the amounts for all contracts should be included in the baseline for a purchased capacity rider that may be approved in Project No. 39246 is an issue that should be decided in that project. B. Conclusions of Law 1. ETI is a "public utility" as that term is defined in PURA § 11.004( 1) and an "electric utility" as that term is defined in PURA§ 31.002(6). 2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051, 36.101-.111, and 36.203. 3. SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation of a proposal for decision in this docket, pursuant to PURA§ 14.053 and TEX. GOY'TCODE ANN. § 2003.049. 4. This docket was processed in accordance with the requirements of PURA and the Texas Administrative Procedure Act, TEX. Gov'T CODE ANN. Chapter 2001. 5. ETI provided notice of its application in compliance with PURA§ 36.103, P.U.C. PROC. R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3). 6. Pursuant to PURA § 33.001, each municipality in ETI's service area that has not ceded jurisdiction to the Commission has jurisdiction over the Company's application, which seeks to change rates for distribution services within each municipality. 7. Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a municipality's rate proceeding. 8. ETI has the burden of proving that the rate change it is requesting is just and reasonable pursuant to PURA § 36.006. 9. In compliance with PURA§ 36.051, ETI's overall revenues approved in this proceeding permit ETI a reasonable opportunity to earn a reasonable return on its invested capital used and useful in providing service to the public in excess of its reasonable and necessary operating expenses.  ---------------- SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE368 PUC DOCKET NO. 39896 10. Consistent with PURA § 36.053, the rates approved in this proceeding are based on original cost, less depreciation, of property used and useful to ETI in providing service. 11. The ADFIT adjustments approved in this proceeding are consistent with PURA§ 36.059 and P.U.C. SUBST. R. 25.23l(c)(2)(C)(i). 12. Including the cash working capital approved in this proceeding in ETI's rate base is consistent with P.U.C. SUBST. R. 25.23l(c)(2)(B)(iii)(IV), which allows a reasonable allowance for cash working capital to be included in rate base. 13. The ROE and overall rate of return authorized in this proceeding are consistent with the requirements of PURA §§ 36.051 and 36.052. 14. The affiliate expenses approved in this proceeding and included in ETI's rates meet the affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.-Austin 1984, no writ). 15. The ADFIT adjustments approved in this proceeding are consistent with PURA§ 36.059 and P.U.C. SUBST. R. 25.231(c)(2)(C)(i). 16. Pursuant to P.U.C. SUBST. R. 25.231(b)(l)(F), the decommissioning expense approved in this case is based on the most current information reasonably available regarding the cost of decommissioning, the balance of funds in the decommissioning trust, anticipated escalation rates, the anticipated return on the funds in the decommissioning trust, and other relevant factors. 17. ETI has demonstrated that its eligible fuel expenses during the Reconciliation Period were reasonable and necessary expenses incurred to provide reliable electric service to retail customers as required by P.U.C. SUBST. R. 25.236(d)(l)(A). ETihas properly accounted for the amount of fuel-related revenues collected pursuant to the fuel factor during the Reconciliation Period as required by P.U.C. SUBST. R. 25.236(d)(l)(C). 18. ETI prudently managed the dispatch, operations, and maintenance of its fossil plants during the Reconciliation Period. 19. The Reconciliation Period level operating and maintenance expenses for the Spindletop Facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a). 20. Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to recover rough production equalization payments reallocated to ETI by the FERC. SOAR DOCKET N O . - PROPOSAL FOR DECISION PAGE369 PUC DOCKET NO. 39896 21. ETI' s rates, as approved in this proceeding, are just and reasonable in accordance with PURA § 36.003. C. Proposed Ordering Paragraphs In accordance with these findings of fact and conclusions of law, the Commission issues the following orders: 1. The Proposal for Decision prepared by the SOAH ALls is adopted to the extent consistent with this Order. 2. ETI' s application is granted to the extent consistent with this Order. 3. ETI shall file tariffs consistent with this Order within 20 days of the date of this Order. No later than ten days after the date of the tariff filings, Staff shall file its comments recommending approval, modification, or rejection of the individual sheets of the tariff proposal. Responses to the Staffs recommendation shall be filed no later than 15 days after the filing of the tariff. The Commission shall by letter approve, modify, or reject each tariff sheet, effective the date of the letter. 4. The tariff sheets shall be deemed approved and shall be become effective on the expiration of 20 days from the date of filing, in the absence of written notification of modification or rejection by the Commission. If any sheets are modified or rejected, ETI shall file proposed revisions of those sheets in accordance with the Commission's letter within ten days of the date of that letter, and the review procedure set out above shall apply to the revised sheets. 5. Copies of all tariff-related filings shall be served on all parties of record. 6. ETI shall prepare and file as part of its next base rate case a study regarding the feasibility of instituting LED-based rates and, if the study shows that such rates are feasible, ETI should file proposals for LED-based lighting and traffic signal rates in that case. If ETI has LED lighting customers taking service, the study shall include detailed information regarding differences in the cost of serving LED and non-LED lighting customers. ETI shall provide the results of this study to Cities and interested parties as soon as practicable but no later than the filing of its next rate case. SOAH DOCKET N O . - PROPOSAL FOR DECISION PAGE370 PUC DOCKET NO. 39896 7. All other motions, requests for entry of specific findings of fact and conclusions of law, and any other requests for general or specific relief, if not expressly granted, are denied. SIGNED July 6, 2012. THOMAS H. WALSTON ADMINISTRATIVE LAW JUDGE STATE OFFICE OF ADMINISTRATIVE HEARINGS ST · li:N D. ARNOLD ADMINISTRATIVE LAW JUDGE STATE OFFICE OF ADMINISTRATIVE HEARINGS ER BU,..,.,.....&.., ...... ADMINISTRAT A.W JUDGE/MEDIATOR STATE OFFICE OF ADMINISTRATIVE HEARINGS // '/ tY ,, . /Jvi~,.,.e~ . ._ "titO D. 10MERLEAU ADMlNISTRi.\.TIVE LAW JUDGE STATE OFFICE OF ADMINISTRATIVE HEARINCS  Attachment A SOAH DOCKET NO. ALJ Schedule I • PUC DOCKET NO. 39896 Revenue Requirement COMPANY NAME Entergy Texas, Inc TEST YEAR END 30..Jun·11 Company AW Company Requested Adjustments AW Test Year Adjustmenlll Test Year To Company AdJusted Total To Test Year Total Electric Reguest Total Electric (a) (b) (c) (d) (e) = (c) + (d) REVENUE REQUIREMENT Operations & Maintenance CM! $ 1,291,684,714 $ (1,075; 148, 117) $ 216,536,597 $ (24,241,886) $ 192,294,731 Regulatoiy Debits and Credits 407.00 $ (6,784,608) $ 12,030,533 $ 5,245,925 $ (324,121) " $ 4,921,804 Accretion Expense """'' ....... $ 212,783 $ (212,783) $ $ $ Interest on Customer Deposits ....... $ $ 68,985 $ 68,985 $ (25.938) "' $ 43,047 Decommissioning Expense $ $ $ $ $ Depreciation & Amortization Expense ''"' $ 76,072,459 $ 22,558,698 $ 98,631,157 $ (6, 761,585) $ 91,869,572 Taxes Other Than Income Taxes """ Si:h G-9 $ 63,023,906 $ (2,533, 159) $ 60,490,747 $ (2,953,747) $ 57,537,000 Federal Income Taxes SQh·A $ (23,407,031) $ 67,296,739 $ 43,889,708 $ 5,920,966 $ 49,810.674 Current State Income Taxes .,,. ... $ (127,519) $ 89,787 $ (37,732) $ 37,732 $ Deferred Federal Income Taxes S¢hA $ 67,051,463 $ (52,089,274) $ 14,962, 189 $ (14,962,189) $ Deferred State Income Taxes ...... $ 812,265 $ (727,918) $ 64,347 $ (84,347) $ Investment Tax Credits 411 00 Sd>A $ (1,611,177) $ (46,429) $ (1,657,606) $ 1,657,606 $ Consolidated Tax Sa11109s Adjustment $ $ $ $ $ Return on Invested Capital $ $ 155,162,991 ~ 155,182,991 ~ {15,379,778) $ 139,783,213 TOTAL $ 1,466,927,255 $ (873,649,947) $ 593,377,308 $ (67,117,267) $ 536,260,041 Plus: Addback: Purchased Power Rider 55500 $ 244,539,884 C1 C10 Addback: Interruptible Services 555 00 $ • Cl • Total Addbacks $ 244,539,884 Total ALJ Revenue Requirement $ 780,799,926 •  Attachment A Customer Assistance 908 $ 9,189,638 $ (7,250,909) $ 1,938,729 $ (67,298) $ 1,871.43~ • Customer Assistance over/under 908 $ 1,747,892 $ (1,747,892) $ $ $ Information & lnstr Advertising 909 $ 937,069 $ (876) $ 936,193 $ (4,056) $ 932,137 Misc. Cust Serv1ce and Information 910 $ 1,151,988 $ 4,764 $ 1,156,752 $ $ 1,156,752 Sales Supervision 911 $ 829 $ 7 $ 836 $ (17.467) $ (16,631) OemonstratinQ & Sellinq Exo 912 $ 730,161 $ 14,522 $ 744,683 $ (16,597) $ 728,086 Advertising Expense 913 $ 110,202 $ (2,379) $ 107,823 $ (58) $ 107,765 M1sc Sates Expense 916 $ 256,775 $ 1,715 $ 258,490 $ (1,390) $ 257,100 $ TOTAL Operations & Maintenance 1,207,264,083 (1 ,071 ,013, 726) 136,250,357 (11,034,115) 125,216,242 • •  Attachment A • SOAH DOCKET NO, PUC DOCKET NO. COMPANY NAME TEST YEAR END 39896 Entergy Texaa, Inc. 30.Jun-11 Teat Year Total (a) Company Adjuslmenta To Test Year (b) Company Requestsd Test Year Total Electrlc (c) ALJ Adjustmenta To Company Raguast fd) ALJ Schedule IU lnvoted Capital ALJ Adjusted Total Eleetrlc !•I= {c) + (dl INVESTED CAPITAL Plant in Servi;e Ae<:umulaled Depraciallon .., $ $ 3,521,368, 187 (1,417 946,172) $ $ (251,512,491) 148,061,290 $ $ 3.269,855.696 (1 269,8(14,882) (1,333,352) "' $ $ 3,266,522,344 11 269 684.882) Net Plant In Service 2.103,422,015 $ (103,451,201) $ 1,999,970,814 ( 1,333,352) 1,998,637,462 $ Construction Work in Progress $ $ $ $ $ Plant Held 10! Future Use $ $ $ $ $ Working Cash Allowance $ $ (2,013,921) $ (2,669,275) s {3, 725, 159) $ (6,414,434) Fuel Inventories $ 53,759,975 $ $ 53,759,975 $ {1,066,490) .. $ 52,693,485 ... Materials and Supplies Prepayments Property Insurance Reserve $ $ $ 29,252,574 7,366,433 $ $ $ {148,396) 59,799,744 $ $ $ 29,252,574 7,218,037 59,799,744 $ $ $ 32,847 916,313 . $ $ $ 29.265,421 8,134,350 59,799,744 lnjunes and Damages Reserve $ (5,589,243) $ $ (5,569,243) $ $ (5,569,243) Coal Car Maintenance Reserve $ 1,400,350 $ $ 1,400,350 $ $ 1,400,350 UnfUnded Pension $ (53,715,841) $ 109,689,386 $ 55,97U45 $ (25,311,236) "' $ 30,662,309 Allowance$ $ 68,914 $ $ 68,914 s $ 68,914 Envuonmenla! Reserves $ 3,412,379 $ (4,474,569) $ {1.062, 1QO) $ $ (1,062,190) Customer Deposit& $ (35,872,476) $ $ (35,812,476) $ $ {35,872,476) Regulatory Assets and Uabilltles $ $ 26,366,859 $ 26,366.859 $ (11,054,084) .. $ 15,312,795 Accumulated OFIT $ {824,338,691) $ 369,007, 144 $ (454,37\,547) $ (2,460,528) M. Onl $ (458,832,075) Rate Case Expenses $ $ 6,175,000 $ 6,175,000 $ (6,175,000) """ $ $ $ TOT Al. INVESTED CAPITAL (RATE llASE) 1,279,1tll!,389 461,910,046 $ 1,740,421,081 (50,176,6119) 1,690,244,412 RATE OF RETURN 5.140% 6.92% 8.2700%. RETURN ON INVESTED CAPITAL $ 155,162,991 155,162,991 (15,379,7781 139,783,213 • •  Attachment A • SOAH DOCKET NO. AW Schedule 1118 PUC DOCKET NO. 39B!Hi Depreciation ex:panse COMPANY NAME Entergy Texas, Inc~ TEST YEAR END 30.Jun-11 Company AW Company Requested AdJuatmenlt AW THtYear Adjustmento Teat Year To Company AdJU$1ed ToTestYoar Total Electric Roguest Toll!! Electric (b) (cl (d)z <•H•l (•} Depreciation Expanse Structures & Improvement& 311 $ 1,095,067 $ 616,683 $ 1,711,750 $ (424,581) $ 1,287, 169 BOiler Plant Equipmen! 312 $ 8,765,278 $ 845,956 $ 9,611,234 $ (2,028,662} $ 7,582,572 TurboGenerator Units 314 $ 2.482,980 $ 2,045,957 $ 4,528,937 $ (1, 105,324} $ 3,423,613 Accessory Electric Equipment 315 $ 2,262,265 $ 395,683 $ 2,657,948 $ (430,004) $ 2,227,944 Misc Power Piant Equip 316 $ 238.086 $ 66,386 $ 302.472 $ (53,873) $ 248.599 Asset R~t11ement ObligatiOn 317 $ (331,958) $ 331,958 $ $ $ Misc Power Plan! Eq'"p 335 $ 1,188 $ (943) $ 245 $ $ 245 Subtotal Production $ 14,510,906 $ 4,301,660 $ 18,612,586 $ (4,042,444) $ 14,770,142 Land Easements 350.2 $ 483,058 $ (65,666) 397,392 $ $ 397,392 Sb'uciures & Improvements 352 $ 417.724 $ (315) 417,409 $ $ 417,409 Station E.qu1pment 353 $ 5,379,875 $ 2.952,519 $ 8,332,494 $ $ 8,332,494 Towers and Fixtures 354 $ 416,765 $ 46,647 $ 463,412 $ (107,469) $ 355,943 POkas and Fixtures 355 $ 4,182.575 $ 779,244 $ 4,961,819 $ $ 4,961,819 OH COnduclors & Devices 356 $ 2.860,208 $ 1,162,693 $ 4,022,901 $ $ 4,022,901 Underground Conductors & Oevtces 358 $ 1.409 $ 5,014 $ 6,423 $ $ 6,423 Roads and Trail& 359 $ 860 $ 2.224 $ 3084 $ 3084 Sublotal Transmission $ 13,722.474 $ 4,882,460 $ 18,604,934 $ 18,497,465 Land Rights 300 2 $ 240,953 $ (30,175) $ 210,778 $ $ 210,778 Structures & lmprovementa 361 $ 127,911 $ 33,069 $ 180,980 $ (9,512) $ 151,468 Slation Equipment J62 $ 3,606,715 $ 363,575 $ 3,970,290 $ (399.946) $ 3,570,344 Poles, Towers & Flxtures 354 $ 6,809,464 $ 1.438,154 $ 8,247,618 $ (1,192,611) $ 7,055,007 OH Conductors & Oevlces 365 $ 3,600,424 $ 3,244,756 $ 6,845,180 $ $ 6,845,180 Underground Conduit 366 $ 438,899 $ 32,544 $ 489,443 $ $ 469,443 Underground Conductors & Devices 367 $ 2,277,438 $ 960,620 $ 3,238,058 $ $ 3,238,056 Line Transformers 368 $ 10,285,939 $ 3,068,781 $ 13,374,720 $ (1,285,193} $ 12,089,527 OH Services 389 $ 2,735,305 $ 1.272, 163 $ 4,007,469 $ 280,720 $ 4,288,189 MetetG 370 $ 1,020,813 $ 394,834 $ 1,415,547 $ $ 1,415,547 install on Customet Premises 371 $ 556,198 $ 919 $ 557,117 $ $ 557,117 S!reel Lighting and Signal 373 $ 62,565 $ !22,617] $ 40048 $ $ 40,048 Subto!al D1stribu«on $ 31,760,723 $ 10,776,623 $ 42,537,346 $ (2,606,542) $ 39,930,804 • Regional Trans & Mkt Ops Hardware 382 $ 12.125 12,125 $ 12,125 Regional Trans & Mk! Ops Soflware 383 $ 673,827 (601) 673,226 $ 673,226 Structur&& & Improvements 390 $ 1,359,296 $ (272,045) $ 1,087,251 $ $ 1,087,251 Office Furniture & Equipment 391 $ 2,514,238 $ 3,318,559 $ 5,832,797 $ $ 5,832,797 Transportation Equlpment 392 $ 955 $ 44,724 $ 45,679 $ $ 45,679 Stores Equipment 393 $ 150,556 $ 176,112 $ 326,668 $ $ 326,668 Tools, Shop. & Garage Eqoipment 394 $ 556,547 $ 66.440 $ 622,987 $ $ 622,987 Laboratory Equipment 395 $ 22,505 $ 254,660 $ 277.365 $ $ 277,365 Power Operated Equipment 396 s 30.044 $ (17, 172) $ 12,872 $ $ 12.672 Commurncation Equipment 397 $ 1,897,978 $ (310,501) $ 1,387,477 $ $ 1,387,477 Misc Equipment 398 $ 47155 $ 123,991 $ 171,146 $ $ 171146 Subtotal General Plant $ 6,379,274 $ 3,364.968 $ 9,764,242 $ $ 9,764.242 ESI DepreclaUon Ee