ACCEPTED 03-14-00706-CV 5038192 THIRD COURT OF APPEALS AUSTIN, TEXAS 4/27/2015 10:27:46 AM JEFFREY D. KYLE CLERK No. 03-14-00706-CV IN THE FILED IN 3rd COURT OF APPEALS THIRD DISTRICT COURT OF APPEALS AUSTIN, TEXAS AT AUSTIN, TEXAS 4/27/2015 10:27:46 AM JEFFREY D. KYLE ENTERGY TEXAS, INC., Clerk Appellant, v. PUBLIC UTILITY COMMISSION OF TEXAS, ET AL., Appellees. Appeal from the 345th Judicial District Court, Travis County, Texas The Honorable Amy Clark Meachum, Judge Presiding ________________________________________________________________ APPELLANT’S REPLY BRIEF _________________________________________________________________ John F. Williams State Bar No. 21554100 jwilliams@dwmrlaw.com Marnie A. McCormick State Bar No. 00794264 mmccormick@dwmrlaw.com DUGGINS WREN MANN & ROMERO, LLP 600 Congress Ave., Ste. 1900 (78701) P. O. Box 1149 Austin, Texas 78767-1149 (512) 744-9300 (512) 744-9399 fax ATTORNEYS FOR APPELLANT ENTERGY TEXAS, INC. ORAL ARGUMENT REQUESTED April 2015 TABLE OF CONTENTS TABLE OF CONTENTS ........................................................................................... i INDEX OF AUTHORITIES.................................................................................... iii STATEMENT OF FACTS ........................................................................................1 SUMMARY OF ARGUMENT .................................................................................1 ARGUMENT AND AUTHORITIES ........................................................................3 I. Discretion alone does not justify the Commission’s decision.........................3 II. The Court may not sustain the Commission’s decision upon the theory that ETI’s total rate case expenses were “too high” or that ETI wantonly incurred expenses.............................................................................6 A. The Commission did not find that ETI’s expenses were excessive or that ETI files rate cases too frequently. ............................6 B. The Court cannot sustain the Commission’s decision upon an unarticulated factual theory. ................................................................10 III. The Commission’s disallowance of ETI’s costs of litigating the incentive compensation issue is arbitrary and capricious and an abuse of discretion. ..................................................................................................12 A. The Commission’s finding that ETI made an unreasonable argument in the underlying rate case is arbitrary and capricious........12 B. Regardless, the Commission’s decision is reversibly wrong on procedural grounds. .............................................................................16 1. The Commission changed its past practice without explanation or advance notice...................................................16 2. Additionally, the Commission effectively and improperly adopted a new rule in this contested case. ................................21 IV. The Commission further erred in quantifying its disallowance of ETI’s expenses of seeking to include financially-based incentive compensation in rates. ...................................................................................24 i V. The Commission’s disallowance of depreciation expense associated with ESI’s efforts in the rate case is not supported by any evidence and is arbitrary and capricious. ......................................................................27 CONCLUSION AND PRAYER .............................................................................31 CERTIFICATE OF COMPLIANCE .......................................................................32 CERTIFICATE OF SERVICE ................................................................................33 APPENDICES .........................................................................................................34 ii INDEX OF AUTHORITIES Cases Bowman Transportation, Inc. v. Arkansas-Best Freight System, Inc., 419 U.S. 281, 95 S.Ct. 438, 42 L.Ed.2d 447 (1974) ............................................15 CenterPoint Energy Entex v. Railroad Comm’n of Tex., 213 S.W.3d 364 (Tex. App. – Austin 2006, no pet.)...........................................27 Citizens to Preserve Overton Park v. Volpe, 401 U.S. 402, 91 S.Ct. 814, 28 L.Ed.2d 136 (1971) ............................................14 City of El Paso v. El Paso Elec. Co., 851 S.W.2d 896 (Tex. App. – Austin 1993, writ denied) ............................. 11, 28 City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179 (Tex. 1994) ..................................................................................4 City of El Paso v. Public Util. Comm’n of Tex., 916 SW.2d 515 (Tex. App. – Austin 1995, writ dism’d by agr.)...........................5 City of Port Neches v. Railroad Comm’n of Tex., 212 S.W.3d 565 (Tex. App. – Austin 2006, no pet.) .............................................5 Continental Imports, Ltd. v. Brunke, No. 03-10-00719-CV, 2011 WL 6938489 *5 (Tex. App. – Austin Dec. 30, 2011, pet. denied) .......................................... 11, 28 Downer v. Aquamarine Operators, Inc., 701 S.W.2d 238 (Tex. 1985) ..................................................................................3 Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex., 173 S.W.3d 199 (Tex. App. – Austin 2005, pet. denied) ............................. 23, 24 Flores v. Employees Ret. Sys., 74 S.W.3d 532 (Tex. App. – Austin 2002, pet. denied) .........................................4 Goeke v. Houston Lighting & Power Co., 797 S.W.2d 12 (Tex. 1990) ..................................................................................11 Hendee v. Dewhurst, 228 S.W.3d 354 (Tex. App. -- Austin 2007, pet. denied) ....................................17 Industrial Utils. Serv. Co. v. Texas Natural Resources Conservation Comm’n, 947 S.W.2d 712 (Tex. App. – Austin 1997, no writ) .................................... 20, 21 Lewis v. Metropolitan Savings & Loan Association, 550 S.W.2d 11 (Tex. 1977) ..................................................................................14 iii McHaney v. Texas Comm’n on Environmental Quality, No. 03-13-00280-CV, 2015 WL 869197 at *8 (Tex. App. – Austin Feb. 27, 2015, no pet. h.) ......................................................................................22 Morgan Drive Away, Inc. v. Railroad Comm'n of Tex., 498 S.W.2d 147 (Tex. 1973) ......................................................................... 11, 28 Office of Pub. Util. Counsel v. Public Util. Comm'n, 878 S.W.2d 598 (Tex. 1994) ................................................................................17 Oncor Elec. Delivery Co. v. Public Util. Comm’n of Tex., 406 S.W.3d 253 (Tex. App. – Austin 2013, no pet.)................................ 4, 17, 19 Pioneer Natural Resources USA, Inc. v. Public Util. Comm’n of Tex., 303 S.W.3d 363 (Tex. App. – Austin 2009, no pet.) ...................................... 5, 26 Professional Mobile Home Transport v. Railroad Comm’n, 733 S.W.2d 892 (Tex. App. – Austin 1987, writ ref’d n.r.e.) ....................... 12, 28 Railroad Commission of Texas v. Lone Star Gas Co., 611 S.W.2d 908 (Tex. Civ. App. – Austin 1981, writ ref’d n.r.e.) ......................15 Starr County v. Starr Indus. Services, Inc., 584 S.W.2d 352 (Tex. App. -- Austin 1979, writ ref’d n.r.e.) ...................... 14, 15 State of Texas’ Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615 (Tex. App. – Austin 2014, pet. filed) ........................................13 Suburban Util. Corp. v. Public Util. Comm'n, 652 S.W.2d 358 (Tex.1983) ...................................................................................5 Texas Bd. of Pharmacy v. Witcher, 447 S.W.3d 520 (Tex. App. – Austin 2014, pet. requested) ..................................4 Texas Health Facilities Comm’n v. Charter Medical-Dallas, Inc., 665 S.W.2d 446 (Tex. 1984) ........................................................................... 4, 10 Texas Medical Association v. Mathews, 408 F.Supp. 303 (W.D. Tex. 1976) ......................................................................15 Vista Medical Center Hosp. v. Texas Mut. Ins. Co., 416 S.W.3d 11 (Tex. App. – Austin 2013, no pet.)....................................... 10, 27 Statutes Tex. Gov’t Code Ann. § 2001.141 .................................................................... 10, 27 Tex. Gov’t Code Ann. § 2001.174.............................................................................3 iv Tex. Util. Code Ann. § 36.051 ........................................................................ 5, 9, 27 Tex. Util. Code Ann. § 36.058 .................................................................................30 Tex. Util. Code Ann. § 36.061 .................................................................... 3, 5, 6, 27 Tex. Util. Code Ann. § 36.203 ...................................................................................9 Other Authorities 5 B. Mezines, J. Stein and J. Gruff, Administrative Law § 51.03 (1979) ...............15 Rules Tex. R. Civ. Evid. 201 .............................................................................................17 Administrative Cases Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 28840 .................................................................................... 17, 25, 26 Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 33309 .................................................................................................17 Application of CenterPoint Energy Houston Electric, LLC for Authority Change Rates, Docket No. 38339 ........................................................................18 Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 ....................................... 9, 10, 16, 18 Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 ........................................... 9, 10, 16, 18 Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment, Docket No. 39896 ......................................................................................... passim Application of Oncor Electric Delivery Co. LLC for Authority to Change Rates, Docket No. 35717 ......................................................................................18 Application of Southwestern Electric Power Co. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 40443............................................18 Proceeding to Consider Rate Case Expenses Severed from Docket No. 28840 (Application of AEP Texas Central Company for Authority to Change Rates), Docket No. 31433 .......................................................................25 v STATEMENT OF FACTS Entergy Texas, Inc. (“ETI”) does not dispute the statements of fact submitted by the Public Utility Commission of Texas (“PUCT” or “Commission”), Office of Public Utility Counsel (“OPUC”), and State Agencies, save in a few respects. Specifically, ETI disputes the Attorney General’s argumentative characterization of ETI’s request concerning financially-based incentive compensation in the underlying rate case, and of the way financially-based incentive compensation has been treated in past PUCT dockets. ETI also disputes the suggestion of OPUC and the Attorney General that the Commission found ETI’s rate case expenses to be “excessive.” ETI discusses these factual inaccuracies more fully below. SUMMARY OF ARGUMENT The Commission’s disallowance of over $522,000 for ETI’s effort to recover incentive compensation expense is arbitrary and capricious for several reasons. The contours of the incentive compensation issue have never been defined, ETI’s argument in the rate case was not materially different from what ETI and other utilities have argued in the past, and ETI actually prevailed on the issue in part. In light of these facts, the Commission’s characterization of ETI’s advocacy as unreasonable is itself unreasonable. 1 More important, the Commission has consistently allowed utilities, including ETI, to recover the expenses of seeking incentive compensation, even when the utilities have been unsuccessful. The Commission has never before said it is unreasonable to incur expense to litigate the incentive compensation issue or any other “long shot” issue. The Commission’s abrupt policy change, without even an acknowledgement of its historical treatment of advocacy costs, at the end of this case, after ETI had already incurred its costs, is arbitrary and capricious and an abuse of discretion. This abuse is further manifest in the Commission’s quantification of the disallowance. The Commission employed a “proxy” for the amount of expense ETI incurred to litigate the incentive compensation issue, faulting ETI for failing to track all of its expenses by issue. But again, the Commission has never before disallowed the entire expense of litigating a single issue in a rate case, certainly not the incentive compensation issue. That is why utilities have not recorded their expenses by issue. If the Commission wanted to impose these new standards, it could and should have done so on a prospective basis. The Commission’s decision to impose the new standards at the end of this case, contrary to the way the agency has historically handled the issue, should be reversed. So should the Commission’s disallowance of over $207,000 in depreciation expense associated with ESI’s efforts on the rate case. The Commission said only 2 that this expense was “unreasonable,” without identifying any fact underlying that ultimate finding. Moreover, there is abundant and undisputed record evidence that ESI’s costs were reasonable, necessary, and fairly charged to ETI and its other affiliates. None of the Attorney General’s arguments presents a legitimate basis upon which to affirm the Commission’s decision, and it should be reversed. ARGUMENT AND AUTHORITIES Two themes run throughout appellees’ briefs. ETI will address those first, and then turn to specific issues. I. Discretion alone does not justify the Commission’s decision. Appellees attempt to justify the Commission’s decision principally by asserting that the Commission has discretion in awarding rate case expenses under Public Utility Regulatory Act (“PURA”) section 36.061(b)(2). See Tex. Util. Code Ann. § 36.061(b)(2). The Commission does have some measure of discretion, but that alone cannot justify its decision here. The Commission must adhere to applicable “guiding” principles in exercising its discretion. Tex. Gov’t Code Ann. § 2001.174(2)(F); Downer v. Aquamarine Operators, Inc., 701 S.W.2d 238, 241- 42 (Tex. 1985). One of the fundamental principles of administrative law is that an agency is bound to make decisions based upon a full consideration of the evidence and a serious appraisal of the facts. E.g., Texas Health Facilities Comm’n v. Charter 3 Medical-Dallas, Inc., 665 S.W.2d 446, 452 (Tex. 1984). Another is that an agency is not absolutely bound to follow its decisions in previous cases in the same way a court must follow controlling precedent. E.g., Oncor Elec. Delivery Co. v. Public Util. Comm’n of Tex., 406 S.W.3d 253, 267 (Tex. App. – Austin 2013, no pet.) (citing Flores v. Employees Ret. Sys., 74 S.W.3d 532, 544-45 (Tex. App. – Austin 2002, pet. denied)). Another guiding principle is that parties to contested cases are entitled to advance notice of what is expected of them in the administrative process. E.g., Oncor Elec. Delivery Co., 406 S.W.3d at 268-69; Flores, 74 S.W.3d at 545. A related rule is that an agency is bound to impose a new policy upon regulated entities via the formal rulemaking process unless the issue is of first impression, flows from an amended statute or rule, or cannot be adequately captured within the bounds of a general rule because the problem is so specialized in nature. E.g., City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179, 188-89 (Tex. 1994); Texas Bd. of Pharmacy v. Witcher, 447 S.W.3d 520, 534 (Tex. App. – Austin 2014, pet. requested). In addition to these basic principles applicable to all administrative cases, PURA includes principles that specifically pertain to the Commission’s decisions on rate case expense recovery. Appellees cite cases that correctly observe that 4 PURA section 36.061(b)(2) affords the agency some discretion in determining what expenses should be allowed.1 However, as this Court recently noted: Although section 36.061(b)(2) gives the Commission the discretion to disallow improper expenses, this discretion is tempered by section 36.051’s mandate that the utility must be allowed to recover its operating expenses and a reasonable return on invested capital ... If the expense can be shown to be actual, necessary and reasonable it should be allowed. Oncor Elec. Delivery Co., 406 S.W.3d at 264 (citing Suburban Util. Corp. v. Public Util. Comm'n, 652 S.W.2d 358, 362–63 (Tex.1983)). In other words, the Commission does not have the discretion to disallow rate case expenses that are reasonably incurred.2 Appellees’ repeated suggestion that the Commission’s discretion effectively insulates its decision from meaningful review is flat wrong. 1 See Tex. Util. Code Ann. § 36.061(b)(2), cited in City of El Paso v. Public Util. Comm’n of Tex., 916 SW.2d 515, 522 (Tex. App. – Austin 1995, writ dism’d by agr.), Pioneer Natural Resources USA, Inc. v. Public Util. Comm’n of Tex., 303 S.W.3d 363, 377 (Tex. App. – Austin 2009, no pet.), & Oncor Elec. Delivery Co. LLC v. Public Util. Comm’n, 406 S.W.3d 253, 264 (Tex. App. – Austin 2013, no pet.). 2 The testimony of OPUC’s witness Nathan Benedict ignores the impact of PURA section 36.051 on rate case expense recovery. See AR Part II, Binder 3, OPUC Exh. 1 (Direct Testimony of N. Benedict at 4). So do appellee’s briefs. OPUC cites City of Port Neches v. Railroad Comm’n of Tex., 212 S.W.3d 565 (Tex. App. – Austin 2006, no pet.) for the proposition that the agency may disallow reasonable expenses. See OPUC’s Brief at 16. That case, discussing rate case expense recovery under the Gas Utilities Regulatory Act, does not say reasonable rate case expenses may be disallowed. It says even though a particular underlying cost of service is determined to be reasonable, the utility’s expense of seeking recovery of that cost is not “automatically” or “as a matter of law” deemed reasonable. City of Port Neches, 212 S.W.3d at 581. In other words, the reasonableness of a utility’s rate case expenses is a fact question separate from the reasonableness of a utility’s underlying cost of service. City of Port Neches undermines the Commission’s decision here, where the Commission made the “impermissible leap” that the reasonableness of an underlying cost of service automatically controls the reasonableness of related rate case expenses. 5 This case implicates all of the principles set forth above. The Commission does not avoid their application simply because it has some discretion in applying PURA section 36.061(b)(2). II. The Court may not sustain the Commission’s decision upon the theory that ETI’s total rate case expenses were “too high” or that ETI wantonly incurred expenses. Appellees also contend that the Commission’s decision was based upon a finding that ETI’s total expense for prosecuting Docket No. 39896 was “excessive” or “unusually high.” The Commission’s order, though, confirms that this was not the basis of the disallowance ETI challenges here. A. The Commission did not find that ETI’s expenses were excessive or that ETI files rate cases too frequently. The Administrative Law Judge (“ALJ”), in the proposal for decision (“PFD”) that was adopted by the Commission, recognized that Docket No. 39896 was complex and labor intensive. He noted that ETI presented 39 witnesses, who discussed hundreds of categories of costs, and that while ETI used the services of 12 attorneys, the other parties and Staff were represented by a total of 15 attorneys.3 3 AR Part I, Binder 2, Item 32 (PFD at 17); AR Part I, Binder 2, Item 55 (Final Order at 1) (adopting PFD). 6 Though the ALJ and Commission found that the expenses of the case were “high,” they did not find that the expenses were too high.4 Nor did they reduce ETI’s expense recovery based upon any finding or conclusion that the total was unreasonable. Rather, the ALJ and Commission expressly rejected OPUC’s and State Agencies’ theories that ETI’s expenses should be reduced on bases other than an “issue-specific” approach.5 In support of their arguments that ETI’s total expenses were unreasonable, State Agencies and OPUC criticized many categories of ETI’s costs. The ALJ discussed and expressly rejected most of those criticisms, finding that: State Agencies’ challenge to ETI witness Gerald Tucker’s testimony was “overly simplistic”;6 State Agencies’ proposal to disallow the expenses of a “lessons learned” memo would encourage inefficiency;7 State Agencies’ challenge of miscellaneous internal rate case expenses should be rejected because ETI proved “in great detail” that they were reasonable;8 ETI had “the better argument” on OPUC’s challenge to expenses associated with the Calpine-Carville purchased power agreement;9 4 AR Part I, Binder 2, Item 32 (PFD at FOF 17); AR Part I, Binder 2, Item 55 (Final Order at FOF 17). 5 AR Part I, Binder 2, Item 32 (PFD at 31-32); AR Part I, Binder 2, Item 55 (Final Order at 2). 6 AR Part I, Binder 2, Item 32 (PFD at 9). 7 Id. at 10-11. 8 Id. at 13. 9 Id. at 14-15. 7 he was “unswayed” by State Agencies’ criticism of ETI’s expert’s review of outside legal fees; the external “legal costs involved do not appear to be inordinate”;10 meal, courier, and taxi expenses were a reasonable part of prosecuting the laborious rate case;11 State Agencies’ identification of “relatively few errors” in categorizing meal expenses does not lead to doubt about the overall accuracy of ETI’s accounting;12 and State Agencies’ challenge to airfare and lodging expense was “vague” and “unproven”.13 The Commission adopted the ALJ’s resolution of all these issues.14 The Commission also refused to accept the ALJ’s recommendation that another category of expense, associated with ETI’s advocacy concerning transmission equalization costs, should be disallowed.15 The Commission ultimately disallowed only a few discrete categories of expense, for reasons specific to those categories.16 Regarding the category at issue here, the Commission gave only one reason for the disallowance: “for Entergy attempting to recover financially-based incentive compensation in base rates.”17 It 10 Id. at 17. 11 Id. at 18-19. 12 Id. at 19. 13 Id. at 21. 14 AR Part I, Binder 2, Item 55 (Final Order at 1). 15 Id. at 3. 16 Id. at 2-3 & FOF 18. 17 Id. at 2. 8 is incorrect to suggest in this appeal that the Commission disallowed any expenses on the basis that the grand total was unreasonably high. It is also incorrect to suggest that the Commission disallowed any expenses based on the purported “frequency” of ETI’s recent rate cases. There is no legal or factual support for the parties’ intimation that ETI files rate cases with unreasonable frequency. The frequency of rate cases is cost-driven.18 PURA guarantees an electric utility rates that afford it a reasonable opportunity to recover a reasonable return on its investment, and to recover its reasonable and necessary expenses. Tex. Util. Code Ann. § 36.051. Expenses, which change over time, are largely recovered through base rates.19 The only Commission-approved way for an electric utility to capture changes in its overall level of base-rate expense is to file a rate case. In the previous ETI rate cases mentioned in appellees’ briefs, the Commission granted ETI substantial base-rate increases and expressly found that the increases were just and reasonable. See Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Mar. 16, 2009, Order at FOFs 24 & 45 & COL 7); Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 18 AR Part II, Binder 3, ETI Exh. 7 (Considine Rebuttal at 5). 19 Some categories of expense, like fuel expenses, are recovered through other methods. Tex. Util. Code Ann. § 36.203. Those categories of expense are not at issue in this case. 9 (Dec. 13, 2010, Order at FOFs 16 & 35 & COL 7). Any suggestion that ETI was unjustified in pursuing those increases is, therefore, unfounded. So is any suggestion that it was unfair for ratepayers to pay the expenses of pursuing those cost increases. The Commission expressly found that the expenses of pursuing those rate cases were just and reasonable. See Docket No. 34800, supra (Feb. 5, 2009, Order at FOF 27 & 45 & COL 7); Docket No. 37744, supra (Dec. 13, 2010, Order at FOFs 18 & 43 & COL 7). In any event, ETI’s pursuit of its statutorily- guaranteed opportunity to recover its costs in the past has no bearing on this case. The Commission did not make any finding that it does. Simply put, the parties invite the Court to affirm the Commission’s disallowance of expenses by relying on contested factual theories that the Commission did not accept or rely on. The Court should not accept the invitation. B. The Court cannot sustain the Commission’s decision upon an unarticulated factual theory. An agency is required to make findings on any factual theory underlying its decision. Tex. Gov’t Code Ann. § 2001.141(b) & (d). Those findings must provide a logical link between the facts and the agency’s application of a statutory standard. E.g., Vista Medical Center Hosp. v. Texas Mut. Ins. Co., 416 S.W.3d 11, 26 (Tex. App. – Austin 2013, no pet.) (citing Texas Health Facilities Comm'n v. Charter Med.-Dallas, Inc., 665 S.W.2d 446, 453 (Tex.1984)). The purpose of this requirement is to inform the parties and the courts of the basis for the agency's 10 decision so that the parties may intelligently prepare an appeal and so that the courts may properly exercise their function of review. E.g., Goeke v. Houston Lighting & Power Co., 797 S.W.2d 12, 15 (Tex. 1990). It is ironic, then, that OPUC faults ETI for failing to challenge the Commission’s observation that ETI’s expenses were “high.”20 ETI did not challenge that finding because there is no indication in the Commission’s order that the observation was a basis for any disallowance. Because the Commission did not articulate that the two disallowances at issue here were based upon a conclusion that ETI’s expenses were “excessive,” the Commission’s order cannot be sustained on this theory. The Court is precluded from affirming the Commission’s order on a factual theory that the Commission did not rely upon in the order itself. E.g., Morgan Drive Away, Inc. v. Railroad Comm'n of Tex., 498 S.W.2d 147, 152 (Tex. 1973) (“We may consider only what was written by the [agency] in its order, and we must measure its statutory sufficiency by what it says,” and “findings of basic [underlying] facts cannot be presumed from findings of a conclusional nature.”); Continental Imports, Ltd. v. Brunke, No. 03-10-00719-CV, 2011 WL 6938489 *5 (Tex. App. – Austin Dec. 30, 2011, pet. denied) (not designated for publication) (citing City of El Paso v. El Paso Elec. Co., 851 S.W.2d 896, 899–900 (Tex. App. – Austin 1993, writ denied); 20 See OPUC’s Brief at 16. 11 Professional Mobile Home Transport v. Railroad Comm’n, 733 S.W.2d 892, 903– 04 (Tex. App. – Austin 1987, writ ref’d n.r.e.)). III. The Commission’s disallowance of ETI’s costs of litigating the incentive compensation issue is arbitrary and capricious and an abuse of discretion. A. The Commission’s finding that ETI made an unreasonable argument in the underlying rate case is arbitrary and capricious. In its order, the Commission said it was unreasonable for ETI to advocate recovery of financially-based incentive compensation in rates because, “[t]he Commission has repeatedly ruled that a utility cannot recover the cost of financially-based incentive compensation because financial measures are of more immediate benefit to shareholders and financial measures are not necessary or reasonable to provide utility services.”21 As ETI acknowledged in its initial brief, it is true that the Commission has in the past referred to a perceived dichotomy between “financial” and “operational” measures as a basis for incentive compensation. But the Commission has not clearly or consistently explained how to determine whether a given incentive program benefits customers versus shareholders such that it is or is not recoverable. The Commission concedes, and this Court has observed, that whether a particular incentive program benefits customers enough to be recoverable in rates is a fact issue to be determined on a 21 AR Part I, Binder 2, Item 55 (Final Order at 2). 12 case-by-case basis.22 See State of Texas’ Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615, 660-61 (Tex. App. – Austin 2014, pet. filed). And as evidenced in Appendix C to ETI’s initial brief, the Commission has not treated materially-similar incentive programs consistently over time. In fact, the Commission was persuaded in part by some of ETI’s testimony in this case, and allowed ETI to recover some $1 million in cost-control incentives that another utility was unable to recover in the past.23 Contrary to appellees’ rhetoric, ETI’s advocacy in this case was not “futile,” “fruitless,” or “unsuccessful.” In light of these circumstances, it makes no sense to characterize ETI’s advocacy as “overly-aggressive” or “unreasonable.” In an attempt to avoid this conclusion, the Attorney General sets up a straw man. The Attorney General contends that the Commission did not fault ETI for arguing about which incentives should be considered recoverable under what it terms the “two bucket” policy. According to the Attorney General, the Commission faulted ETI for something else -- arguing to eliminate the distinction between the “buckets.” First, and most important, the Commission did not say anything like that. Second, the two “arguments” the Attorney General attempts to distinguish are shades of the same thing. Whether a particular incentive program 22 E.g., PUCT’s Brief at 5. 23 Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment, Docket No. 39896 (Final Order at 4-5) (allowing recovery of incentive compensation programs tied to “cost control” measures). 13 falls in one bucket or another is not just a matter of superficial labeling. It requires the fact-finder to decide whether a given program “more immediately” benefits shareholders or ratepayers. ETI’s position was that its incentive compensation programs at issue in this case benefit customers substantially and meaningfully and should be recovered.24 That is the same thing as arguing that ETI’s programs fall in the bucket that is recoverable from customers. The Attorney General’s “bucket” argument does not hold water. OPUC suggests this case presents a simple question of evidentiary sufficiency. It does not. An agency decision may pass the “substantial evidence” test and still be invalid for arbitrariness. Starr County v. Starr Indus. Services, Inc., 584 S.W.2d 352, 355 (Tex. App. -- Austin 1979, writ ref’d n.r.e.) (citing Lewis v. Metropolitan Savings & Loan Association, 550 S.W.2d 11, 13-14 & 16 (Tex. 1977)). In determining whether an agency has acted arbitrarily or capriciously, a court must decide whether the agency order was based on a consideration of all relevant factors. Starr County, 584 S.W.2d at 355-56 (citing Citizens to Preserve Overton Park v. Volpe, 401 U.S. 402, 91 S.Ct. 814, 28 L.Ed.2d 136 (1971)). There must appear a rational connection between the facts and the decision of the agency. Starr County, 584 S.W.2d at 356 (citing Bowman 24 Id., ETI Exh. 36 (Gardner Direct at 29-33 of 77); ETI Exh. 50 (Gardner Rebuttal at 2-10 of 18); ETI Exh. 15 (Hartzell Direct at 3-31 of 31); ETI Exh. 53 (Hartzell Rebuttal at 2-15 of 15); PFD at 166-176. 14 Transportation, Inc. v. Arkansas-Best Freight System, Inc., 419 U.S. 281, 95 S.Ct. 438, 42 L.Ed.2d 447 (1974); 5 B. Mezines, J. Stein and J. Gruff, Administrative Law § 51.03, at 51-33 (1979)). Stated differently, the reviewing court must remand “. . . if it concludes that the agency has not actually taken a hard look at the salient problems and has not genuinely engaged in reasoned decision-making.” Starr County, 584 S.W.2d at 356 (citing Texas Medical Association v. Mathews, 408 F.Supp. 303, 305 (W.D. Tex. 1976)). The testimony of OPUC’s witness Nathan Benedict does not reasonably support the Commission’s decision in this case. Mr. Benedict generally testified that the Commission excluded financially-based incentive compensation from ETI’s rates set in Docket No. 39896.25 But he did not acknowledge that, in the same docket, the Commission allowed recovery of costs it had previously disallowed because they were supposedly “financially-based” incentives. And contrary to OPUC’s suggestion,26 the Commission may not use its own “experience” to fill in evidentiary gaps. Railroad Commission of Texas v. Lone Star Gas Co., 611 S.W.2d 908, 911 (Tex. Civ. App. – Austin 1981, writ ref’d n.r.e.). The Commission’s characterization of ETI’s argument in the rate case is not reasonable in light of the record or its past decisions. 25 AR Part II, Binder 3, OPUC Exh. 1 (Benedict Direct at 8). 26 OPUC’s Brief at 14. 15 B. Regardless, the Commission’s decision is reversibly wrong on procedural grounds. Even if the appellees’ characterization of ETI’s advocacy on this issue were in line with the facts, the Commission’s decision to disallow the expenses of the advocacy was arbitrary and an abuse of discretion. 1. The Commission changed its past practice without explanation or advance notice. As ETI explained in its initial brief, though many utilities have sought to include incentive compensation in rates, the Commission has never before disallowed the cost of making unsuccessful incentive compensation arguments. In fact, the Commission has expressly determined that other utilities’ rate case expenses were reasonable, necessary, and recoverable from ratepayers, even in cases where the utilities made unsuccessful arguments on incentive compensation. See Appendix D to ETI’s Appellant’s Brief. The Commission has also allowed ETI and its predecessor to recover rate case expenses in dockets where ETI made similarly unsuccessful requests in the past. See Docket No. 34800, supra (Mar. 16, 2009, Order at FOF 27); Docket No. 37744, supra (Dec. 13, 2010, Order at FOF 18). The Commission cannot point to any case where it has disallowed the 16 expenses of making unsuccessful arguments about incentive compensation, or for making some other argument the Commission deems a “long shot.”27 The Commission contends its decision in this case is not a departure from its earlier decisions because ETI’s request in this case was different from requests in previous cases. That is not so. In every one of these past cases, a utility proposed to recover incentive costs that were “financially based.” For example: In Docket No. 28840, AEP sought to recover its entire test-year level of incentive compensation expense, even though only 34% of it was set through “operational” measures. Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 28840 (Aug. 15, 2005, Final Order at FOFs 165- 67); In Docket No. 33309, part of the incentive compensation AEP sought to include in rates was “related to financial incentives.” Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 33309 (Mar. 4, 2008, Order on Rehearing at FOF 82); In Docket No. 34800, ETI’s predecessor unsuccessfully sought to include in rates its incentive compensation costs that were “financially-related,” arguing even those costs meaningfully 27 OPUC argues that this Court may not consider orders from previous Commission dockets because they are not part of the administrative record in this case. See OPUC’s Brief at 19. This Court rejected that same argument in Oncor. See Oncor Elec. Delivery Co. LLC v. Public Util. Comm’n of Tex., 406 S.W.3d 253, 267 (Tex. App. – Austin 2013, no pet.). This Court specifically acknowledged it may consider how the Commission has treated other utilities to determine whether a particular policy is new in a given case. Id. at 267. The Court can take judicial notice of agency decisions like these, which are publicly available and the authenticity of which is readily verifiable. See Office of Pub. Util. Counsel v. Public Util. Comm'n, 878 S.W.2d 598, 600 (Tex. 1994) (holding that court of appeals must take judicial notice of agency's published order if asked to do so) (citing Tex. R. Civ. Evid. 201(b)(2)); Hendee v. Dewhurst, 228 S.W.3d 354, 377 n.30 (Tex. App. -- Austin 2007, pet. denied) (likening agency decisions to court decisions with regard to judicial notice). 17 benefited customers. See Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800, ETI Exh. 72 (Direct Testimony of J. Hartzell, PhD, on Remand);28 In Docket No. 35717, Oncor sought to recover its entire test- year level of incentive compensation expense, even though about 25% of it was “related to financial measures.” See Application of Oncor Electric Delivery Co. LLC for Authority to Change Rates, Docket No. 35717 (Nov. 30, 2009, Order on Rehearing at FOFs 91-93); In Docket No. 37744, ETI sought to include in rates its incentive compensation costs that were “financially-based,” arguing even those costs meaningfully benefited customers. See Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744, ETI Exh. 14 (Direct Testimony of J. Hartzell, PhD);29 In Docket No. 38339, CenterPoint sought to include in rates both its short-term and long-term incentive compensation plans, but the Commission included only the former in rates, finding it was “directly tied to metrics such as customer service and safety.” See Application of CenterPoint Energy Houston Electric, LLC for Authority Change Rates, Docket No. 38339 (Jun. 23, 2011, Order on Rehearing at FOFs 81-83); and In Docket No. 40443, Southwestern Electric Power Company sought to recover its roughly $10.7 million test-year level of incentive compensation, even though roughly half of it was tied to “financial measures.” See Application of Southwestern Electric Power Co. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 40443 (Mar. 6, 2014, Order on Rehearing at 13 & FOFs 214-220). 28 See Appendix A. 29 See Appendix B. 18 There is no material distinction between ETI’s request in this case and the utility proposals made in previous cases. OPUC argues that the Commission’s past decisions did not establish “policy” because they were “not contested.”30 But again, the Commission expressly found in each of these past cases that it was reasonable for the utility to recover its expenses, and never carved out costs of making unsuccessful arguments about incentive compensation. The fact that parties may have agreed with these decisions does not undermine them. If anything, it bolsters them. To be clear, ETI does not contend that the Commission can never change its policy on a given issue. But when it does, the Commission must give advance notice that it is considering a policy change, and articulate a reason if a change is made. The Attorney General does not even suggest that the Commission met these requirements in this case.31 The Commission’s failure in each of these respects is reversible error, just like it was in Oncor Elec. Delivery Co., 406 S.W.3d 253. Appellees’ attempts to distinguish Oncor are not persuasive. First, this Court in Oncor reversed the Commission’s decision because the Commission did not explain its departure from a past practice. The same thing happened in this case – the Commission had always acted one way under a given set of facts, and then took the opposite path on the same set of facts. Second, another basis for this 30 OPUC’s Brief at 20. 31 See PUCT’s Brief at 33. 19 Court’s reversal of the Commission’s decision in Oncor was that the Commission departed from its past practice when it was too late for the utility to do anything about it. The same thing happened in this case. The administrative process at issue began when Docket No. 39896 was filed. At that time, the Commission had given no indication whatsoever that it would not continue to allow recovery of otherwise reasonable expenses related to litigating incentive compensation. The opportunity to file rebuttal testimony in the severed expense docket did not adequately protect ETI’s interests. By the time the new standard was proposed and vetted in the severed expense docket, ETI had already incurred the very costs proposed to be disallowed. The fact that ETI had the opportunity to file rebuttal testimony in the expense docket does not mean ETI had proper notice of the Commission’s new policy at the critical time, before ETI incurred the costs at issue. All the appellees cite Industrial Utils. Serv. Co. v. Texas Natural Resources Conservation Comm’n, 947 S.W.2d 712, 718 (Tex. App. – Austin 1997, no writ) as support for the Commission’s decision. But that case proves ETI’s point. In Industrial Utils. Serv. Co., the utility sought a rate increase, asked the agency to deny it, and then sought to recover its expenses of prosecuting the rate case. This Court upheld the agency’s denial of the expenses. This case is quite different. Here, ETI sought and received a rate increase, based in part upon ETI’s successful 20 request to recover what have historically been deemed to be financially-based incentive compensation. It is not, therefore, unreasonable for ETI to seek the expenses of making that request. Moreover, the agency in Industrial Utils. Serv. Co. did not have a historical practice of allowing recovery of expenses for making unwanted rate proposals. Here, in contrast, the Commission has consistently allowed recovery of expenses for making even unsuccessful incentive compensation arguments. The Commission has never disallowed the expenses of seeking to include financially-based incentive compensation in rates. Industrial Utils. Serv. Co. is simply inapposite to this case. 2. Additionally, the Commission effectively and improperly adopted a new rule in this contested case. The Commission’s imposition of a new policy in this case also constitutes improper ad hoc adjudication. Appellees contend the agency did not craft a “rule” of general applicability in this case, but only applied the statutory principle that a utility may not recover “unreasonable” expenses.32 State Agencies also contend the scope of the Commission’s decision is not clear, so it cannot be a “rule.”33 But regardless of whether the Commission meant it is unreasonable to take any “long shot” position or just to seek recovery of financially-based incentive compensation, it is clear the Commission intended to apply its new allocation of risk to the 32 E.g., PUCT’s Brief at 35; OPUC’s Brief at 25-26; State Agencies’ Brief at 17 & 19. 33 State Agencies’ Brief at 17. 21 industry going forward. The Commission did not in its order identify any facts peculiar to this case that suggest the new policy applies only to this case. The Commission broadly declared that it is “unreasonable” to incur expense to litigate the recoverability of financially-based incentive compensation. And the Commission based its conclusion solely upon something the Commission characterized as “well-established policy” – not facts.34 Again, Chairman Nelson confirmed at an open meeting that the Commission was in this case setting a “new policy.”35 She even observed, on the record, that the subject is more properly addressed in a rulemaking.36 Appellees contend this statement somehow implies the opposite. They cite this Court’s recent decision in McHaney v. Texas Comm’n on Environmental Quality, No. 03-13-00280-CV, 2015 WL 869197 at *8 (Tex. App. – Austin Feb. 27, 2015, no pet. h.). In McHaney, this Court considered a TCEQ Commissioner’s statement that “if there is a need for clarity in our rules, I would encourage our staff to look at that and see if we need to go through the rulemaking or provide some other guidance.” McHaney, 2015 WL 869197 at *8 (emphasis in original). The Court viewed that statement as support for the conclusion that the agency did not intend to impose a “rule” in the contested case at issue. Chairman Nelson, however, did not suggest that the Commission 34 AR Part I, Binder 2, Item 55 (Final Order at 2). 35 See April 11, 2013 Transcript at 7:25-8:14. 36 Id. 22 was following established policy or merely question whether the Commission’s rules reflect the policy clearly enough. Chairman Nelson unequivocally acknowledged that the PUCT was adopting a “new policy” in this case, and recognized that new agency policy should be adopted through the formal rulemaking process. The Attorney General and State Agencies also argue that the agency’s formal adoption of a rule after this case indicates that the Commission was not adopting a rule in this case.37 That is a non-sequitur. The fact that the agency ultimately followed the formal rulemaking process does not shed any light on what the agency intended earlier, in this case. The Commission declared for the first time in this case that it is “unreasonable” to propose to recover what in the past has been deemed “financially-based” incentive compensation, and that it is “unreasonable” to incur expenses for such a proposal. It was improper to impose these new policies outside the context of a formal rulemaking because none of the justifications for ad hoc adjudication apply. State Agencies cite Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex., 173 S.W.3d 199, 212 (Tex. App. – Austin 2005, pet. denied) as support for the Commission’s action. That case recognizes that an agency may engage in ad hoc adjudication when it “may not have had sufficient experience with a particular 37 See PUCT’s Brief at 38; State Agencies’ Brief at 23. 23 problem to warrant rigidifying its tentative judgment into a hard and fast rule.” Entergy Gulf States, 173 S.W.3d at 212. But the Commission has had plenty of experience considering the expenses of advocacy related to incentive compensation issues, as discussed above. If the Commission wanted to change its policy going forward, it was bound to do so in the context of a formal rulemaking. IV. The Commission further erred in quantifying its disallowance of ETI’s expenses of seeking to include financially-based incentive compensation in rates. The Commission used a “proxy” to measure the disallowance discussed above. Specifically, the Commission determined the percentage of ETI’s requested rate increase that was attributable to its unsuccessful incentive compensation argument, and then disallowed that same percentage of ETI’s rate case expenses. The Commission has never done that before. The Commission’s sole justification for using a proxy is that ETI did not track all of its expenses by issue over the life of the rate case. But utilities have not tracked their rate case expenses by issue because the Commission has never before imposed a disallowance for litigating an issue. Indeed, the Commission has repeatedly allowed utilities to recover the expense of making the very same argument ETI made here. It is the Commission’s after-the-fact change in policy, not a failing of ETI’s, that caused 24 the difficulty in measuring the actual expenses of litigating a particular issue in this case. The problem with the Commission’s “proxy” approach is that it does not logically approximate the actual amount of costs ETI incurred to litigate the incentive compensation issue. Instead, the Commission’s proxy method is keyed to the value of the litigated issue. State Agencies argue that there is a logical correlation between the value of a litigated issue and the amount of money a utility spends to litigate it. There is not. It is true that the raw, maximum value of a litigation position might represent an upper limit on the expenses that may reasonably be incurred to pursue it. But that is where any correlation stops. It may cost relatively little to pursue even a high-dollar-value litigation position. The value of the position simply does not inform what it actually costs to litigate. Contrary to the Commission’s argument, the agency’s use of a proxy in this case does not resemble the way the agency quantified a disallowance in Docket No. 28840. There, the Commission disallowed half of the expenses associated with a witness’s testimony — specifically, the expenses of Dr. Goodfriend’s testimony on quality-of-service issues.38 Dr. Goodfriend’s testimony was 117 38 See Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 28840 (Jul. 2, 2004, PFD at 125); Proceeding to Consider Rate Case Expenses Severed from Docket No. 28840 (Application of AEP Texas Central Company for Authority to Change Rates), Docket No. 31433 (Mar. 3, 2006, Final Order at FOF 29). 25 pages long. Roughly 60 pages of it concerned the quality-of-service issue.39 The disallowance of half the cost of the testimony almost exactly correlates with the portion of the testimony the Commission found was flawed. That is, the Commission disallowed the actual expenses of unreasonable testimony in Docket No. 28840, not some unrelated amount of money based upon the value of the position the witness was advocating. State Agencies and OPUC point to the Pioneer Natural Resources case as support for the Commission’s use of a proxy to measure a disallowance.40 The Commission did not use a proxy, or “infer” anything, to quantify the disallowance in that case. In Pioneer, the Commission limited the utility to recovering only 35% of the cost of a computer system because only 70% of the system served the utility, and because only half the system was operational in the test year. The 35% multiplier was, as this Court noted, simply the mathematical product of the 70% and 50% components (i.e., 70% x 50% = 35%). Pioneer Natural Resources, 303 S.W.3d at 369. The Commission’s quantification of the expense it deemed unreasonable in Pioneer contrasts sharply with what the Commission did here. Here, the Commission did not quantify the actual expenses of making an argument. The Commission quantified something else, based upon the value of the argument. The Commission imposed its new policy at the end of the case, after the expenses 39 Id. (Direct Testimony of S. Goodfriend at 11-71 of 117). 40 See State Agencies’ Brief at 27 (citing Pioneer Natural Res., 303 S.W.3d at 369). 26 had already been incurred and tracked according to historically accepted practices, when it was too late for ETI to do anything about it. V. The Commission’s disallowance of depreciation expense associated with ESI’s efforts in the rate case is not supported by any evidence and is arbitrary and capricious. As ETI explained in its initial brief, the Commission disallowed over $207,000 of depreciation expense associated with assets ESI employees used in their work on the rate case. The Commission in its order said only that this expense was “not reasonable.”41 That is an “ultimate” finding of fact, stated in statutory language. See Tex. Util. Code Ann. §§ 36.051(rates must permit utility to recover “reasonable” and necessary operating expenses) & 36.061(b)(2) (contemplating recovery of “reasonable” rate case expenses). The Commission was bound to, but did not, make any underlying finding of fact supporting this ultimate finding. See Tex. Gov’t Code Ann. § 2001.141(d). The Court may not presume findings of underlying facts. E.g., Vista Medical Center Hosp., 416 S.W.3d at 26. The Commission’s decision is reversible for this reason alone. CenterPoint Energy Entex v. Railroad Comm’n of Tex., 213 S.W.3d 364, 373 (Tex. App. – Austin 2006, no pet.) (reversing agency’s disallowance of expense as “unreasonable” because agency failed to make underlying findings permitting court to review reasonableness of its decision). 41 AR Part 1, Binder 2, Item 55 (Final Order at FOF 18(a)). 27 Assuming arguendo the Commission could escape that flaw in its decision, the only basis the ALJ articulated for his decision on this issue was rank speculation that ETI might not incur depreciation expense if it had hired an unaffiliated company to do the same work.42 This speculation is not supported by any evidence in the record, and it is directly contrary to the Commission’s treatment of test-year ESI depreciation expense in the underlying rate case. In response, the Attorney General now says Entergy did not explain what assets were being depreciated. This was not a stated reason for the disallowance in the Commission’s order or the ALJ’s PFD. The order cannot be sustained on this basis. Morgan Drive Away, Inc., 498 S.W.2d at 152; Continental Imports, Ltd., 2011 WL 6938489 *5 (citing City of El Paso, 851 S.W.2d at 899–900); Professional Mobile Home Transport, 733 S.W.2d at 903–04. More important, this detail is in the record. As noted by ETI’s witness Michael Considine in this case, Company witness Stephanie Tumminello explained (in the rate case) the process by which depreciation costs were billed to ETI.43 Ms. Tumminello explained what ESI assets were being depreciated.44 Her testimony was part of the record officially noticed in this case.45 42 AR Part I, Binder 2, item 32 (PFD at 12); AR Part I, Binder 2, Item 55 (Final Order at 1). 43 AR Part II, Binder 3, ETI Exh. 6 (Oct. 25, 2012, Considine Supp. Direct at 4). 44 See Docket No. 39896, supra, ETI Exh. 41 (Tumminello Direct at 79). 45 AR Part III, Vol. A (Transcript of Hearing on Merits at 16). 28 The Attorney General argues that Ms. Tumminello’s testimony pertained only to test-year expenses and not expense incurred while ESI was working on the rate case. The Attorney General ignores that Ms. Tumminello’s testimony was filed with ETI’s application in Docket No. 39896, which included both requests for a base-rate increase and recovery of rate case expenses.46 Ms. Tumminello did sponsor schedules and testify about test-year ESI depreciation expense. But her testimony was not limited to test-year processes or expenses. Her explanation of what assets ESI depreciates, how the expense is recorded by project, why the expense is necessary, and how it is billed and allocated to operating companies like ETI addresses the company’s practices generally.47 And Ms. Tumminello confirmed, based upon a survey she conducted, that ESI’s costs are in line with those of peer service companies and do not include any profit or markup.48 Ms. Tumminello’s testimony that control processes ensure depreciation costs billed to ETI are no higher than the costs billed to other affiliates is equally unqualified.49 A PricewaterhouseCoopers opinion letter further confirms that ESI has established processes generally to ensure that it bills only actual costs, and that its charges to 46 See Docket No. 39896, supra, (Application) & ETI Exh. 8_ (Considine Direct at 18). 47 See Docket No. 39896, supra, ETI Exh. 41 (Tumminello Direct at 79-86 & SBT-26 (list of depreciable assets by account number)). 48 Id. at 82-84. 49 Id. at 84-85 & Tumminello Direct Exh. SBT-15 (Attachment 8, “Affiliate Billing Process Controls”). 29 ETI are no higher than costs billed to other affiliates.50 Mr. Considine’s testimony in the severed expense docket echoes these conclusions multiple times.51 The Attorney General further muses that the depreciation expense for ESI’s work in the rate case might contain depreciation on aircraft. But again, Ms. Tumminello testified generally that ESI aircraft depreciation expense is “included as a component of total flight costs of ESI aircraft” and not included in general depreciation.52 The spreadsheet Mr. Considine sponsored in the expense docket, showing expenses charged to ETI for ESI’s services in the rate case, does not include any “flight” or “aircraft” costs.53 This argument is specious. The Attorney General now contends ETI’s evidence does not meet the standards for affiliate expenses set out in Docket No. 16705 and PURA section 36.058. See Tex. Util. Code Ann. § 36.058(c). This argument is incredible, given that the Commission expressly found in this case that “Entergy met the requirements in PURA § 36.058 regarding payments to its affiliates for its rate- case expenses.”54 Clearly, the “heightened affiliate standard” was not the basis for the Commission’s disallowance of ESI depreciation expense. 50 Id. at Tumminello Direct Exh. WP SBT-4. 51 AR Part II, Binder 3, ETI Exh. 4 (Considine Supp. Direct at 3-4 of 5); AR Part II, Binder 3, ETI Exh. 5 (Considine Supp. Direct at 3-5 of 6); AR Part II, Binder 3, ETI Exh. 6 (Considine Supp. Direct at 3-5 of 5); AR Part II, Binder 3, ETI Exh. 7 (Considine Rebuttal at 9-11 of 11). 52 See Docket No. 39896, supra, ETI Exh. 41 (Tumminello Direct at 83-84). 53 AR Part II, Binder 3, ETI Exh. 7 (Considine Rebuttal at Exh. MPC-R-1). 54 Order at 3, FOF 19, & COL 11. 30 Because the Commission’s disallowance of this expense is not supported by any evidence in the record, and because it cannot reasonably be reconciled with its treatment of analogous expense in the rate case, the decision must be reversed. CONCLUSION AND PRAYER For the foregoing reasons, Entergy Texas, Inc. respectfully requests the relief it requested in its appellant’s brief. Respectfully submitted, DUGGINS WREN MANN & ROMERO, LLP By: /s/ Marnie A. McCormick John F. Williams State Bar No. 21554100 jwilliams@dwmrlaw.com Marnie A. McCormick State Bar No. 00794264 mmccormick@dwmrlaw.com P. O. Box 1149 Austin, Texas 78767-1149 (512) 744-9300 (512) 744-9399 fax ATTORNEYS FOR APPELLANT ENTERGY TEXAS, INC. 31 CERTIFICATE OF COMPLIANCE I certify that this document contains 7,474 words in the portions of the document that are subject to the word limits of Texas Rule of Appellate Procedure 9.4(i), as measured by the undersigned’s word-processing software. /s/ Marnie A. McCormick Marnie A. McCormick 32 CERTIFICATE OF SERVICE As required by Texas Rule of Appellate Procedure 9.5, I certify that on the 27th day of April, 2015, the foregoing document was electronically filed with the Clerk of the Court using the electronic case filing system of the Court, and that a true and correct copy was served on the following lead counsel for all parties listed below via electronic service: Elizabeth R. B. Sterling Environmental Protection Division Office of the Attorney General P. O. Box 12548 (MC 066) Austin TX 78711-2548 Counsel for Appellee Public Utility Commission of Texas Rex D. VanMiddlesworth Benjamin Hallmark Thompson Knight LLP 98 San Jacinto Blvd., Ste. 1900 Austin TX 78701 Counsel for Appellee Texas Industrial Energy Consumers Katherine H. Farrell Administrative Law Division Office of the Attorney General P. O. Box 12548 (MC018-12) Austin TX 78711-2548 Counsel for Appellee State Agencies Ross Henderson Office of Public Utility Counsel 1701 N. Congress Ave., Ste. 9-180 P. O. Box 12397 Austin TX 78711-2397 Counsel for Appellee Office of Public Utility Counsel /s/ Marnie A. McCormick Marnie A. McCormick 33 APPENDICES A. Direct Testimony of Dr. J. Hartzell on Remand in PUCT Docket No. 34800 B. Direct Testimony of Dr. J. Hartzell in PUCT Docket No. 37744 34 APPENDIX A Direct Testimony of Dr. J. Hartzell on Remand in PUCT Docket No. 34800 SOAR Docket No. XXX-XX-XXXX PUC Docket No. 34800 EGSI - 2007 Rate Case EGSI Remand Ex. No. 72 DOCKET NO. ~ APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION GULF STATES, INC. FOR § AUTHORITY TO CHANGE RATES § AND TO RECONCILE FUEL COSTS . § OF TEXAS DIRECT TESTIMONY OF JAY C. HARTZELL ON BEHALF OF ENTERGY GULF STATES, INC. SEPTEMBER 2007 2007 Texas Rate Case 10. I DOCKET N O . - - - - ENTERGY GULF STATES. INC. DIRECT TESTIMONY OF JAY C. HARTZELL 2007 TEXAS RATE CASE - TABLE OF CONTENTS Page I. Witness Identification and Qualifications 1 II. Purpose and Organization of Testimony 2 Ill. Financlal·Based Incentive Compensation as a Tool for Improving Consumer Welfare 4 A. The Positive Effect of Incentive Compensation on Utility Customer Weffare 4 B. The Reasons for Providing Financial·Based Incentive Compensation 10 EXHIBIT Exhibit JCH· 1 Resume 2007 Texas Rate Case J().2 Entergy Gulf States, Inc. Page1of19 Direct Testimony of Jay C. Hartzea 2JXJ7 Texas Rate Case 1 I. WITNESS IDENTIFICATION AND QUALIFICATIONS 2 Q. PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS 3 ADDRESS. 4 A. I am Jay C. Hartzell. I am an Associate Professor of Finance at the 5 Mccombs School of Business at the University of Texas at Austin. My 6 work address is Department of Finance, T:he University of Texas at Austin, 7 1 University Station B6600, Austin, Texas, 78712. 8 9 Q. FOR WHOM ARE YOU TESTIFYING? 10 A. I am testifying on behalf of Entergy Gulf States, Inc. ("£GSI"). 11 ( 12 Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND 13 PROFESSIONAL EXPERIENCE. 14 A. I provide my complete resume in my Exhibit JCH-1. In brief, I obtained a 15 Bachelor of Science degree (cum laude) from Trinity University in May 16 1991, with majors in Business Administration and Economics. After 17 graduating, I went to work as a consuhant for Hewitt Associates, in The 16 Woodlands, Texas. Hewitt is a -consulting firm that specializes in benefits 19 and compensation. While there, I specialized in the area of defined 20 contribution plans. I left Hewitt lo go to graduate school at the University 21 of Texas at Austin in 1993. I completed my PhD in finance there in May 22 1998. Upon graduating, I took a job as an Assistant Professor of Finance 23 at New York University's Stem School of Business, where I worked 2.007 Texas Rate Case W.-3 Entergy Gulf States, Inc. Page2of 19 Direct Testimony of Jay C. Hartzell 2007 Texas Rate Case 1 until 2001. At that time, the University of Texas at Austin hired me as an 2 Assistant Professor at the McCombs School of Business .("McCombs 3 Schooi-), where I have work~ since. I was promoted to the rank of 4 Associate Professor (with tenure), effective in the fall 2006. I also now 5 serve as the Director of the Real Estate Finance and Investment Center at 6 the McCombs School. 7 8 a. WHAT ARE YOUR MAIN AREAS OF RESEARCH? 9 A. My primary research interest is in the area of corporate governance. This 10 area encompasses several topics, including executive compensation, the 11 role of institutional investors, mergers and acquisitions, and boards of 12 directors. I have also written papers in the area of real estate finance, with 13 many of these also focusing on the areas of corporate governance, using 14 data from that industry. 15 16 II. PURPOSE ANO ORGANIZATION OF TESTIMONY 17 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 18 A. EGSI has asked me to comment on the use of financial-based goals in a 19 company's incentive compensation plans, and how those goals affect 20 consumer welfare. I first address the factors specific to the utility industry 21 that support the conclusion that the presence of financial-based goals in 22 an incentive compensation plan is consistent with consumers' interssts. I 23 then tum to the broader topic of how an incentive <:e>mpensation plan 2007 Texas Rate Case J()..4 Entergy Gulf States, Inc. Page3of 19 Direct Testimony of Jay C. Hartzell 2001 Texas Rate-case 1 including financial measures provides incentives to a firm's employees to 2 take actions that improve customer welfare. 3 4 a. WHY ARE YOU OUALlflED TO ADDRESS THESE SUBJECTS AND TO 5 PROVIDE THIS TESTIMONY? 6 A. In addition to my formal training as a student, I have studied and 7 conducted research on corporate governance, including executive 8 compensation, for more than 10 years, starting with work in graduate 9 school, including my dissertation. Since that time, I have written nine 1O papers on corporate governance topics, plus my dissertation. Six of those 11 have been published in peer-reviewed academic journals, including the ( 12 top such journals in the field of finance. I have presented and discussed 13 papers on corporate governance (including compensation) at the major 14 conferences in the field. I have also taught related topics to PhD students, 15 as part of a PhD class in empirical corporate finance. 16 17 Q. DO YOU SPONSOR ANY EXHIBIT? 18 A. Yes. My exhibit is listed in the table of contents to this testimony. 2007 Texas Rate Case 10..S Entergy Gulf States, Inc. Page4of19 Direct Testimony Qf Jay C. Hartzell 2007 Texas Rate Case 1 Ill. FINANCIAL-BASED INCENTIVE COMPENSATION AS A TOOL FOR 2 IMPROVING CONSUMER WELFARE 3 Q. WHAT IS YOUR UNDERSTANDING OF THE COMMISSION'S 4 RATEMAKING TREATMENT OF A UTILITY'S INCENTIVE 5 COMPENSATION EXPENSES? 6 A. It is my understanding that in recent cases, the Public Utility Commission 7 has had a policy of excluding from base rates compensation that is based 8 on the firm's financial measures, but has allowed compensation that is 9 based on operational measures such as quality of service, reliability, 10 public safety, cost control, power plant performance, reduction of 11 absenteeism, and cost containment. 12 13 Q. WHAT ISSUES REGARDING INCENTIVE COMPENSATION WILL YOU 14 ADDRESS? 15 A. I will comment on the coexistence of these two types of incentives 16 (financial-based and operational-based), and the role of financial-based 17 incentives in ultimately contributing to customer welfare. 18 19 A. The Positive Effect of Incentive Comoensation on 20 Utility Customer Welfare 21 a. IS THERE A LINK BETWEEN CUSTOMER WELFARE AND A FIRM'S 22 FINANCIAL PERFORMANCE? 23 A. Yes. Satisfied customers clear1y experience greater customer welfare, all 24 else equal, as they are happy with the products they consume. This is 2007 Texas Rate Case 10-6 Entergy Gulf States, Inc. Page5of 19 Direct Testimony of Jaye. Hartzell 2007 Texas Rate Case 1 true not only for customers in unregulated industries, but also for 2 customers in regulated industrieS. For example, customers who 3 experience fewer power outages will suffer less disutility from being 4 without power, but will also spend less time and expend fewer resources 5 compensating for outages, or complaining about the service they have 6 received. 7 In addition to benefiting eustomers, greater satisfaction tends to 8 benefrt the firm, as well. Satisfied customers are likely to buy more of the 9 firm's products, which leads to higher revenues and profits, and a higher 10 stock price, all else equal. Satisfied customers are also more likely to be 11 retained as customers, and customer retention helps the firm's profitability ( 12 via higher net revenues than they would have .experienced without such 13 satisfaction. Companies with better reputations for customer satisfaction 14 are also more likely to attract new customers who can leam of firms' 15 reputations prior to making their purchasing decisions. At the same time, 16 because improved customer satisfaction tends to lead to improved 17 financial performance, the prospect for improved financial results can play 18 a positive role in motivating mana~rs to improve customer welfare. 19 Although regulated utility -companies do not deal with the same type 20 of competitive dynamics faced by unregulated companies, the general 21 concepts r~ated to customer satisfaction still apply. For example, 22 potential industrial customers and other large users face choices when 23 they decide where to locate a new facility (a factory, a campus, etc.) or 2007 Texas Rate Case Entergy Gulf states, Inc. Page6of 19 Oirec:t T eslimony of Jay C. HartzeU 2007 Texas Rate Case 1 whether to expand a current facility or instead build a new one, or whether 2 to produce their own power rather than rely on the local utility company. 3 Holding the rates they are offered constant, if the customer has a facility in 4 a location with an electricity provider who provides good service, then the 5 customer's satisfaction with that service would make the customer more 6 likely to expand that facility, and would make the customer less likely to 7 look for alternative locations or to self-generate, all else equal. A 8 customer that is more likely to expand in the current location rathe~ than 9 l~k elsewhere would in tum benefit -the financial performance of the 10 customer's current utility company. - 11 This conceptual link between customer welfare and financial 12 performance also applies to residential utilify customers. Residential 13 customers can choose, for example, between gas (including propane) 14 appliances and electrical appliances. The more satisfied they are with 15 their electrical service provider, the more likely they are to ~oose 16 electrical appliances (all else equal). This customer behavior in response 17 . to good service again leads to better financial performance for the electric 18 utility. 19 20 Q. WHY WOULD TODAY'S FINANCIAL HEALTH OF THE FIRM 21 POSITIVELY AFFECT FUTURE CUSTOMER WELFARE? 2007 Texas Rate Case 10-8 Entergy Gulf States, Inc. Page7of 19 Direct Testimony of Jay C. Hartzell 2007 Texas Rate Case 1 A. I can see at least five channels through which a more financially 2 successful company will be associated with greater customer welfare both 3 now, and in the future. 4 First, companies that are financially healthy will be able to raise 5 capital at lower cost. Put another way, companies that are less healthy 6 financially and therefore are more likely to enter into financial distress 7 (including bankruptcy) will face higher costs of capital. These higher costs 8 of capital will in tum lead to higher rates for customers and lower customer 9 welfare. This channel is straightforward: as a .company gets closer to 10 distress, the expected costs of distress increase, and lenders (including 11 bondholders) charge more for their loans to the firm. Because the cost of 12 debt is one of the key components of the cost of capital, these higher 13 borrowing costs lead to a higher oven1ll cost of capital. In addition, if 1he 14 higher costs of capital are large enough, this effectively limits the less 15 healthy finn's acce5s to funds, implying that financially healthy firms have 16 broader access to capital than their less healthy oountefparts. This cost of 17 capital effect is especially relevant to the utility industry given the 18 industry's reliance on large capital spending projeGts and use of debt 19 capital. 20 Second, in an industry where prices that finns can chatge are 21 regulated, if managers have incentives to increase fmancial performance, 22 then this will lead them to focus on cutting oosts. By linking managers' 23 pay to stock price, for example, managers will, among other goals, attempt 2007 Texas Rare Case J().9 Entergy Gulf States, Inc. Page8of 19 Direct Testimony of Jay C. HartzeQ 2001 Texas Rate case 1 to increase stock price by operating mere efficiently. This improved 2 efficiency will lead to a lower cost basis in the future than what one would 3 have observed without such incentives, which will in tum lead to lower 4 future prices for customers (compared to .what would likely have been 5 charged otherwise) and increased customer welfare. 6 Third, the utility industry is characterized by high fixed costs of 7 production and economies of scale. This cost structure implies that larger 8 firms can operate at lower marginal costs (all else equal). Thus, as higher 9 customer service or satisfaction leads to greater customer attraction and 1O retention, these in tum lead to growth in the customer base and revenues. 11 The magnitude of these effects may be smaller for a regulated utility than 12 for a firm in an ~nregulated industry, but I see no reason why the effects 13 would not still be present and go in the same direction. Such growth in 14 reven.ues is associated with greater financial perfonnance, but the 15 Increase in size allows the firm to produce more cheaply due to the large 16 fixed costs in the industry and economies of scale. These cost savings 17 again materialize in lower future rates for customers (compared to what 18 they would have been without the growth in the1irtn's operations). 19 Fourth, managers who care about the financial performance of the 20 company are more likely to make better investment decisions. The stock 21 market, via analysts who follow the firm's behavior and traders who act 22 based on their beliefs about the firm's prospects, acts as a monitor of a 23 wide range of managerial actions, including investment decisions. Stock- 2007 Texas Rate Case 10-10 Entergy Gulf States, Inc. , Pege9of 19 Direct Testimony of Jay~. Hartz.en 2007 Texas Rate'Case 1 price based incentives can help discipline managers, and constrain ihem 2 from investing in ways that might not benefit the finn. 3 Fifth, companies that are less healthy financially - or, to put it 4 another way, closer to financial distress - will likely experience greater 5 costs, which will in tum be passed on to customers. This is because 6 stakeholders who have relationships with the company will demand more 7 favorable terms from the firm in order to compensate them for the greater 8 risk of dealing with a less healthy a>mpany. For example, consider a 9 supplier who sells machinery to a utility company that is not financialty 10 healthy (or is believed to be near distress). Such a supplier will likely 11 demand higher prices from the utility before committing to any sort of ( 12 investment in a relationship with the utility, In order to oompensate for the 13 risk that the revenues from the relationship may cease to exist before the 14 supplier can recoup its costs. These effects are predicted to be stronger 15 where firm-specific investments are required - such as customized 16 machinery - or, the relationship is expected to nave a longer tenn. In 17 addition, suppliers to less healthy finns (firms that are nearer distress) are 18 likely to provide less attractive terms of trade --for example, requiring <:ash 19 payment rather than accepting trade credit. 8oth of these - higher prices 20 or worse trade and mK:lit terms - wHI materialize as higher costs for the 21 utility, which will in turn likely be passed on to customers via higher .priGes 22 for energy. SimUar arguments can be made for other stakeholders <>f the 23 firm, such as employees of the firm. Employees of firms that a~ mor-e 2007 Texas Rate Case 1-0-1] Entergy Gulf States, Inc. Page 10of 19 Direct Testimony of Jay C. Hartzell 2007 Texas Rate Case · 1 likely to become financially distressed will likely demand higher wages in 2 order to compensate them for the risks they face in working for such a 3 company. Absent a StJfftcient wage differential, financially distressed firms 4 are likely to lose skilled and talented employees and to find it difftcUlt to 5 attract good new ones, further exacerbating these firms' situations. 6 In summary, by providing managers with incentive compensation 7 that is based in part on the financial performance of the firm, managers 8 have incentives to keep the firm financially healthy. A utility's financial 9 health is very likely to benefit customers via lower oosts than otherwise 10 would be experienced, which in tum lead to lower rates than otherwise 11 would be the case. These lower costs occur because of (I) a lower cost of 12 capital; (ii) more efficient operations; (iii) greater scale of production; 13 (iv) better investment decisions by managers; and {v) better prices and/or 14 terms from stakeholders, such as suppliers and employees. 15 16 B. The Reasons for Providing Financial-Based Incentive Compensation 17 Q. WHAT TOPICS DO YOU DISCUSS IN THIS SUBSECTION OF YOUR 18 TESTIMONY? 19 A. I explain how incentive compensation is used as an effective tool in 20 aligning the interests of a firm's employees and its stakeholders, including 21 the firm's customers and shareholders. I also discuss how this improved 22 incentive alignment motivates a firm's employees to take actions that tend 23 to ultimately benefit the firm-including customers and shareholders. 2007 Texas Rate Case 10~12 Entergy-Gulf States, Inc. Page11of19 Direct Testimony of Jay C. Hartzel 2007 Texas Rate C8se 1 a. WHAT IS THE BASIC UNDERLYING THEORY OF INCENTIVE 2 COMPENSATION AS IT APPLIES TO A PUBLICLY·TRADED 3 COMPANY? 4 A. The traditional paradigm of incentive-based compensation centers around 5 the role of incentive pay in solving a •moral hazard• problem, where the 6 principals involved cannot observe the actions of an agent who acts on 7 their behalf. This agent is expected to act in a way that maximizes his or 8 her personal welfare, which is not necessarily the same set of actions that 9 would maximize the welfare of the principals. This potential conflict of 10 interest, tenned an agency problem, gives rise to a role for incentive 11 compensation. Because the principats cannot observe or write eontraots 12 based on the ager.it's actions (because it is assumed that those actions 13 cannot be observed or legally verified), incentives are put in place such 14 that the agent is more likely to benefit when they take the oourse of action 15 that is desired by the principals. SpecificaUy, the agent receives higher 16 pay when he or she takes actions that benefit the principals. 17 Understanding this, the agent is mor.e likely to take those actions desired 18 by the principal - put forth more effort, -pick better projects, or shirk less, 19 tor example. 20 The typical view in finance is from the .perspective of the 21 sharehotders: shareholders are the principals and owners of the finn, and 22 they hire managers to act as agents on their behalf. Incentive pay has a 23 role in tt)at it provides for greater compensation to managers when there 2007 Texas Rate Case 10-13 Entergy Guff Slates, Inc. Page12of19 Direct Testlmony of Jay C. Hartzetl 2007 Texas Rate Case 1 are indications that they took actions that benefited shareholders. One of 2 the most fundamental and accepted theoretical results from the principal- 3 agent academic literature is that an agenfs pay should be linked to a 4 particular performance measure (such as stock price, accounting profits. 5 or a score based on customer satisfaction) if that measure provides an 6 additional informative signal of the manager's actions. 7 If a principal (such as the Commission) has a goal of maximizing 8 customer welfare. then the same principal·agent theory still applies. In 9 this context, pay should optimally be related to any performance measure 10 that contains marginally useful information about whether managers acted 11 in a way that Is consistent with maximizing customer welfare. In other 12 words. even if the goal is to maximize customer welfare, pay should also 13 be related to financial performance so long as the financial perfonnance 14 measures contain some additional information about customer welfare. 15 16 Q. HOW CAN INCENTIVES BASED ON FINANCIAL MEASURES IMPROVE 17 MANAGERS' FOCUS ON CURRENT AND FUTURE CUSTOMER 18 SERVICE? 19 A In the extreme, this most basic principal-agent theory is developed in a 20 one-period setting, without regard to future periods. In this set.up, the 21 manager acts, outcomes are realized at the end of the period (depending 22 in part on those actions). and the manager receives his or her pay. 2007 Texas Rate Case 10-14 Entergy Gulf States, Inc. Page13of 19 Direct Tatimony of Jfl'f C. Hartzell 2007 Texas Rate Case 1 A more realistic setting would allow for multiple periods, where both 2 managers and principals would have to consider not only their immediate 3 actions, but also their expected Mure actions, and trade-offs between 4 what they choose to do today versus what they may receive in the future. 5 This more realistic setting leads to another common problem or incentive 6 conflict between managers and principals: these parties having differing 7 time horizons. Typically, managers are expected to have a shorter..term 8 focus than otherwise would be optimal. As a result of their possibly 9 shorter time horizons, managers may make decisions that focus solely on 10 the short term at the expense of the long-term. Incentive compensation 11 tied to measures that look both to the short-tenn (such as the current 12 year's earnings) and long-term {such as stock price) is an accepted 13 solution to extend the managers' time horizons. and to balance short-term 14 and long-tenn perspectives, in decision-making and execution. 15 16 a. DOES EXTENDING THE MANAGERS' TIME HORIZONS HAVE A 17 POSITIVE EFFECT ON EXPECTED CONSUMER WELFARE? 18 A. Yes. In the context of maximizing -customer welfare. the horizon of the 19 manager is an important issue. To the extent the Commission wishes to 20 maintain and .enhaooe -customer welfare not only in the short-run, but also 21 in the future, financial measures like stock price performance play a useful 22 role in an incentive oompensation structure in order to aocomplish this 23 objective. '2007 T-exas Rate Case 10-15 Entergy Gulf States, Inc. Page14fof 19 Direct Testimony of Jay C. Hartzell 2007 Texas Rate Case 1 In addition to providing incentives for managers to optimize their 2 decisions in the current year. a financial-based incentive plan can provide 3 this perspective by capitalizing the long-term benefits of managers' 4 decisions. In other words, via incentives based .on financial perfonnance 5 measures such as stock Priee. the expected long-term impact of 6 managers' decisions has immediate impad on financial perfonnance 7 measures, thereby affecting managers' pay and incentives. Stock prices 8 are based on the present value of the firm's expected future cash flows. 9 So, by making a manager's compensation depend on stock price. one ties 10 the manager's wealth to expected future cash flows. This makes him ~ 11 her more willing to make decisions that produce long-term benefits for the 12 firm, even if it is at the cost of short.term cash flows or profits. 13 14 a. HOW DO FINANCIAL-BASED INCENTIVES EXTEND THE MANAGERS' 15 TIME HORIZONS TO THE BENEFIT OF CONSUMER WELFARE? 16 A. To see how incentive pay affects customer welfare over multiple years, 17 first take an extreme hypothetical example where managers are only 18 compensated based on this year's customer welfare. This could create an 19 incentive for the manager to make deeisions that would sacrifice the future 20 of the finn (and its customers) for the benefit of the Immediate welfare of 21 customers. The manager might •over·lnvest" in immediate customer 22 service, weakening the finn's future financial position and its ability to 23 provide high-quality. low cost service in the future. With limited resources, 2007 Texas Rate Case 10~16 Entergy Guff States, Inc. Page 15of 19 Direct T.estimony of Jay C. HartzeM 2007 Texas Ratecase 1 the firm might decide to pay for this •over-investmenr In immediate 2 customer service by taking money from long-tenn maintenance spending 3 or capital investment that would produce long-term efficiency or 4 productivity gains. 5 But, by linking a manager's pay at least in part to the financial 6 health of the firm, one forces the manager to think about more than just 7 the short term, and to consider future years and the future performance of 8 the firm when they decide on a course of action. If the manager over- 9 invested in immediate customer welfare, then it would weaken the firm's 10 financial position and potentially, consumers' future welfare. Conversely, 11 by weighing not only immediate customer welfare, but also financial ( 12 measures like stock price that are related to the firm's short- and long.term 13 viability, the manager has the incentive to position the firm to provide 14 higher levels of customer welfare in the future. 15 16 a. WHY SHOULD THERE BE A POSITIVE RELATION BETWEEN 17 CUSTOMER WELFARE AND FINANCIAL PERFORMANCE? 18 A. Back to the basic theory, then, financial measures should be part of the 19 manager's a>mpensation structure if one wants to maximize customer 20 welfare so long as those financial measures are related to {or are signals 21 of) customer welfare. This is plausible and r.easonable for several 22 reasons. First, customer welfare is difflcult to measure oompletely, so it is 23 unlikely that objective customer-based measures that one <:an use in a 2007 T-exas Rate Case 10-17 Entergy Gulf States, Inc. Page16of19 Direct Testimony of Jay C. Hartzell 2001 Texas Rate case 1 compensation structure will fully capture what is trying to be measured. 2 Then, so long as the firm's f11ancial performance is poaitively correlated 3 with customer welfare, in this period or in the future, financial performance 4 should optimally enter the compensation structure with positive weight 5 (meaning that the manager receives greater compensation when the 6 financial performance of the firm is greater). The accepted literature on 7 compensation theory Is clear that less-noisy (I.e ., more accurate) signals 8 of managers' actions are preferred over noisier (less accurate) signals, but 9 even noisy signals of managers' actions should be included in the optimal 10 compensation contract. Thus, so long as a financial measure such as 11 stock price is correlated with customer welfare (beyond what the 12 operational measures can explain), then it should enter the compensation 13 structure of the manager. The more accurate it is as a signal, the greater 14 weight (or bigger role) it should receive. 15 16 a. ARE THESE FINANCIAL THEORIES SUPPORTED BY EMPIRICAL 17 EVIDENCE? 18 A. Yes. There are multiple empirical studies published in peer-reviewed 19 academic joumals that report evidence consistent with these hypotheses. 20 21 a. HOW DO THESE EMPIRICAL STUDIES SUPPORT THESE 22 HYPOTHESES? 2007 Texas Rate Case 10-18 Entergy Gulf States, Inc. Page 17of 19 Direct T.estlmony of Jay C. Hartzell 2007 Texas 'Rate·Case 1 A. There is a wealth of existing empirical evidence that is supportive of these 2 theories. First, published papers have shown that customer satisfaction 3 measures are positively correlated with firms' financial perfonnance. In 4 other woros, firms with higher customer satisfaction scores tend to have 5 better financial performance, not worse. This fact from the -data is 6 consistent with the arguments above that more-satisfied customers are 7 expected to result in higher profits and belier overall financial 8 performance. This finding also suggests that financial measures -can play 9 a positive role in motivating managers to improve customer welfare. This 10 result of a positive relation between financial performance and customer 11 satisfaction is inconsistent with the idea that managers tend to maximize ( 12 financial performance to the detriment of customers, which should help 13 alleviate some fears that contracts incorporating financial-performance 14 incentives will lead managers to diminish their customers' welfar:e for the 15 sake of greater financial performance and higher compensation. In the 16 data, financial success tends to be associated with gr.eater wstomer 17 satisfaction, not iess. 16 There is also evidence that higher wstOmer satisfaction scores are 19 associated with higher market values across firms. This empirical result is 20 consistent with the widely-held notion that the s1ock market is a 21 mechanism by which the long-term benefits of customer welfare are 22 capitalized into a present value measure. This 1esult that higher customer 23 satisfaction scores are associated with higher market values has been 2007 Texas Rate Case 10-19 Entergy Gulf States, Inc. Page18of19 Direct Testlmony of Jay C. Hartzell 2007 Texas Rate Case 1 shown for a broad set of companies in general. and also for the utility 2 industry in particular. 3 Empirical evidence also suggests that these relations between 4 customer satisfaction and financial petformance change as customer 5 satisfaction becomes very high. This change is consistent with the idea 6 that there are diminishing (financial) returns to improving customer 7 satisfaction. implying that it becomes more and more expensive to keep 8 improving customer satisfaction. Such an increasing cost of customer 9 satisfaction is consistent with the notion discussed earlier that providing 1O managers with incentive compensation that is only based on this pe~'s 11 customer welfare measures might lead managers to over-invest in current 12 customer welfare to the detriment of the long-tenn financial health of the 13 firm, potentially endangering future customer welfare, as well. As also 14 discussed earlier, including measures such as stock price in the 15 compensation structure of managers can help provide incentives for 16 managers to not only consider the immediate welfare of customers, but to 17 also weigh future years' customer welfare and the fenancial health of the 18 company when they make decisions while running the firm. 19 The evidence on firms in or near financial distress is also consistent 20 with the opinions presented earlier that firms that are more likely to enter 21 into financial distress are more likely to encounter significant costs of 22 distress, which could materialize in the form of higher future costs for 23 customers and lower future customer welfare {compared to the <:0sts that 2007 Texas Rale Case 10-20 Entergy Gulf States, Inc. Page 19of 19 Direct Testimony of Jay C. Hartz.eH 2007 Texas Rate Case 1 would have been realized without the firm in distress). There is evidence 2 that finns with more debt (relative to their equity) suffer more when their 3 industries do not do well. Heavily indebted firms tend to invest less and 4 lose more sales in industry downturns when compafed to their less- 5 indebted industry counterparts, which would be expected to lead to higher 6 average costs in industries with economies of scale, such as the utility 7 industry. In addition, it has been shown that these finns with more debt 8 tend to be penalized by customers and suppliers, again leading to greater 9 costs than what one would have experienced without such distress. 10 . 11 Q. CAN YOU DRAW ANY CONCLUSIONS BASED UPON THESE ( 12 COMMONLY ACCEPTED ECONOMIC AND FINANCIAL PRINCIPLES? 13 A. Yes. These theoretical arguments are intuitive and based on sound, 14 commonly accepted economic and financial principals Thus, it is possible 15 to draw conclusions based upon the ·application of logic to fundamental 16 finance principles. In my opinion, the existing empirical evidence is 17 supportive of the conclusion that incentive compensation siructures that 18 include financial-based performance measures-tend to benefit oonsumers. 19 20 Q. DOES THIS CONCLUDE YOUR PREFILED DIRECT TESTIMONY? 21 A. Yes. UIJ7 Texas Rate Case 10-21 APPENDIX B Direct Testimony of Dr. J. Hartzell in PUCT Docket No. 37744 SOAH Docket No. 473~10-1962 PUC Docket No. 37744 ETI Exhibit No. 14 DOCKET NO. - - - ( APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION TEXAS, INC. FOR AUTHORITY § TO CHANGE RATES AND § OF TEXAS RECONCILE FUEL COSTS § DIRECT TESTIMONY OF JAY C. HARTZELL, PHO. ON BEHALF OF ENTERGY TEXAS, INC. DECEMBER 2009 2009 ETI Rate Case 4-357 ENTERGY TEXAS, INC. ( DIRECT TESTIMONY OF JAY C. HARTZELL, PHO. 2009 RATE CASE TABLE OF CONTENTS I. Background and Introduction 1 II. Overview of the Issues Surrounding Incentive Compensation 3 Ill. The False Dichotomy Between Compensation Tied to "Financial" Measures and Compensation Tied to "Operational" Measures; and the Benefits of Cost Control, Profitability, and Stock Price Measures 8 IV. Costs to Customers of Discouraging the Use of Incentive Compensation That is Linked to Cost Control, Profitability and Stock Prices 18 V. Response to Common Arguments Against Incentive Compensation Linked to Cost Control, Profitability and Stock Prices from the Customers' Perspective 23 VI. Empirical Evidence Supporting Testimony 25 VI I. Conclusion 28 EXHIBITS EXHIBIT JCH-1 Curriculum Vitae of Jay C. Hartzell 2009 ETI Rate Case 4-358 Entergy Texas, Inc. Page 1 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 I. BACKGROUND AND INTRODUCTION 2 Q. PLEASE STATE YOUR NAME, TITLE, AND BUSINESS ADDRESS. 3 A. My name is Jay C. Hartzell. I am an Associate Professor of Finance at the 4 Mccombs School of Business at the University of Texas at Austin. My 5 business address is Department of Finance, The University of Texas at 6 Austin, 1 University Station 86600, Austin, Texas 78712. 7 8 Q. ON WHOSE BEHALF ARE YOU TESTIFYING? 9 A. I am testifying on behalf of Entergy Texas, Inc. ("ETI" or the "Company"}. 10 11 Q. PLEASE STATE YOUR EDUCATION, PROFESSIONAL AND WORK 12 EXPERIENCE. 13 A. I obtained a Bachelor of Science degree (cum laude) from Trinity 14 University in May 1991, with majors in Business Administration and 15 Economics. After graduating, I went to work as a consultant for Hewitt 16 Associates, in The Woodlands, Texas. Hewitt is a consulting firm that 17 specializes in benefits and compensation. While there, I specialized in the 18 area of defined contribution plans. I left Hewitt to go to graduate school at 19 the University of Texas at Austin in 1993. l completed my PhD in finance 20 there in May 1998. Upon graduating, I took a job as an Assistant 21 Professor of Finance at New York University's Stern School of Business, 22 where I worked until 2001. At that time, the University of Texas at Austin I \ 23 hired me as an Assistant Professor at the Mccombs School of Business 2009 ETI Rate Case 4-359 Entergy Texas, Inc. Page 2 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case / 11 ' 1 ("Mccombs School ), where I have worked since. I was promoted to the 2 rank of Associate Professor (with tenure), effective in the fall 2006. 3 Beginning in the fall of 2008, I was given the title of Allied Bancshares 4 Centennial Fellow. I also now serve as the Executive Director of the Real 5 Estate Finance and Investment Center at the Mccombs School. My 6 current curriculum vitae is attached as Exhibit JCH-1. 7 8 Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE A REGULATORY 9 COMMISSION? 10 A. Yes. I have submitted written testimony on incentive compensation issues 11 and testified on behalf of the Company before the Public Utility 12 Commission of Texas ("Commission" or "PUCT") in PUCT Docket No. 13 34800, and on behalf of Entergy Louisiana, LLC before the Louisiana 14 Public Service Commission on incentive compensation issues in Docket 15 No. U-20925. I have also submitted written testimony on behalf of Entergy 16 Arkansas, Inc. before the Arkansas Public Service Commission on 17 incentive compensation issues in Docket No. 09-084-U. 18 19 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 20 A. The purpose of my testimony is to discuss the extent to which incentive 21 compensation - including compensation based on dollar-based measures 22 such as cost control, profitability, and stock prices - is linked to and 23 benefits customers' interests for companies such as ETI. 2009 ETI Rate Case 4-360 Entergy Texas, Inc. Page 3 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 11. OVERVIEW OF THE ISSUES SURROUNDING INCENTIVE 2 COMPENSATION 3 Q. WHAT FORMS OF INCENTIVE COMPENSATION DO YOU FOCUS ON 4 IN YOUR TESTIMONY? 5 A. The focus of my testimony is on incentive compensation that is linked to 6 cost control measures (for operating costs and capital expenditures), 7 profitability measures (including earnings and operating cash flow), and 8 stock prices. Compensation that is linked to these sorts of measures - for 9 companies generally and for ETI in particular - include annual incentive 10 plans, long-term incentive plans, restricted stock grants, and stock option 11 grants. The compensation could come in the form of cash (as in annual 12 incentive plans), stock or stock-based units (as in ETl's long-term 13 incentive plan, or "L TIP"), or options. 14 15 Q. WHAT IS YOUR UNDERSTANDING OF HOW COMPENSATION BASED 16 ON COST CONTROLS, PROFITABILITY AND STOCK PRICES HAS 17 BEEN CHARACTERIZED IN RECENT PUCT RATE DECISIONS? 18 A. In such cases, compensation that is linked to cost controls, profitability 19 and stock prices as discussed in the previous question has commonly 20 been referred to as incentive compensation that is based on "financial 21 measures." This category of incentives has been distinguished from 22 incentive compensation that is based on measures that are not 23 denominated in dollars, such as customer satisfaction, reliability, and 2009 ETI Rate Case 4-361 Entergy Texas, Inc. Page 4 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 safety metrics, which has commonly been categorized as incentive 2 compensation based on "operational measures." As I discuss later in my 3 testimony, I view this as a false dichotomy for the purposes of assessing 4 whether customers benefit from a particular form of incentive 5 compensation. 6 7 Q WHY DO FIRMS USE INCENTIVE COMPENSATION IN GENERAL, AND 8 COMPENSATION BASED ON COST CONTROLS, PROFITABILITY AND 9 STOCK PRICES MORE SPECIFICALLY? 10 A. Incentive compensation is a prevalent tool used to attract, motivate, and 11 retain the .qualified and talented employees needed to ensure that a 12 business can continue to operate successfully. To understand why it is so 13 widely used, it is first useful to draw a distinction between the level and 14 form of compensation. The level of compensation can be thought of as 15 the total dollar value of compensation received by an employee from all 16 sources, including salary, cash incentive-based pay, the value of 17 long-term incentives such as stock performance units and options granted 18 (albeit typically applicable to a much smaller group of employees), and the 19 value of benefits. In order to attract and retain employees, this level 20 needs to be in line with the labor market for a particular type of employee, 21 whether it is an engineer, a maintenance worker, or a chief executive 22 officer. Otherwise, all things equal, that same employee will take a job 23 with a company that is offering the more attractive level of pay and 2009 ETI Rate Case 4-362 Entergy Texas, Inc. Page 5 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 benefits. Company witness Kevin G. Gardner discusses the overall 2 reasonableness of ETl's level of compensation in his direct testimony. 3 4 Q. HOW DOES THE FORM OF COMPENSATION DIFFER FROM THE 5 LEVEL OF COMPENSATION? 6 A. The form of compensation can be thought of as the split of total 7 compensation across these components - for example, how much is paid 8 via salary versus annual incentive-based compensation. Holding the total 9 level of compensation fixed at the proper market level, the form of 10 compensation is important because it can help motivate employees to 11 engage in behaviors that positively impact the operational efficiency of the 12 firm, or positively affect its cost structure. At the same time, the form of 13 compensation is important to attract and retain certain types of employees 14 that offer a skill set or a particular talent that is important to the company's 15 operations. For example, if a compensation plan provides for incentive 16 payments if goals are met - such as controlling costs at some level - then 17 according to basic economic theory, employees will be motivated to work 18 harder toward those goals. More subtly, such incentive pay will tend to 19 attract and retain employees who believe that they are especially good at 20 controlling costs because they will expect higher compensation under 21 such a plan. This implies that a firm seeking to manage costs will find it 22 valuable to institute such an incentive compensation plan as part of the ( 2009 ETI Rate Case 4-363 Entergy Texas, Inc. Page 6 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 design of the form of compensation, while keeping the level of 2 compensation at a competitive market-based amount. 3 4 Q. WHAT IS YOUR UNDERSTANDING OF THE COMMISSION'S 5 PREVIOUS VIEW ON ALLOWING THE RECOVERY OF INCENTIVE 6 COMPENSATION EXPENSE THROUGH RATES? 7 A. My understanding of the Commission's recent rulings on this issue is that 8 the Commission has distinguished between compensation tied to what it 9 has termed operational measures and compensation tied to what it has 10 termed financial measures. Generally, the Commission has not allowed 11 for the recovery of incentive compensation tied to financial measures 12 through rates, but has allowed for the recovery of incentive compensation 13 tied to operational measures. The core rationale for this distinction has 14 been that it has not been sufficiently demonstrated that incentive 15 compensation linked to financial measures is in the public interest or of 16 direct benefit to customers. The decisions in those previous cases, 17 however, do not reflect a review or consideration of the relevant literature 18 or other matters I discuss below, all of which support a conclusion that 19 allowing utilities to use incentive pay based on cost control, profitability, 20 and stock prices is properly viewed as in the public interest and is 21 expected to be of direct benefit to customers. 2009 ETI Rate Case 4-364 Entergy Texas, Inc. Page 7 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case ( \ 1 Q. HOW WOULD YOU SUMMARIZE YOUR OPINION ON THE ISSUE OF 2 WHETHER INCENTIVE COMPENSATION BASED ON COST 3 CONTROLS, PROFITABILITY, AND STOCK PRICES BENEFITS 4 CUSTOMERS? 5 A. In my opinion, a well-designed compensation plan that includes incentive 6 compensation tied to cost controls, profitability, and stock prices would 7 tend to provide greater benefit to customers than an otherwise similar 8 compensation plan that did not include any such incentive compensation. 9 I discuss the details below, but the overarching basis for my opinion is as 10 stated above: incentive compensation based on cost control, profitability, 11 and stock prices helps companies attract, motivate, and retain talented 12 employees, and by doing so, both customers and shareholders directly 13 benefit. Moreover, if ETl's inc~ntive compensation were only based on 14 non-dollar-based measures such as safety and reliability, customers 15 would tend to be worse off, because such a plan would not provide 16 employees with incentives to look after the financial health of the 17 Company. The important point is that customers and shareholders both 18 benefit from well-designed, balanced compensation plans that provide 19 employees with the appropriate level of compensation and that include 20 incentives based on cost control, profitability, stock prices, and 21 non-dollar-based measures such as reliability, safety and customer 22 satisfaction. i I \ ,, 2009 ETI Rate Case 4-365 Entergy Texas, Inc. Page 8 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 111. THE FALSE DICHOTOMY BETWEEN COMPENSATION TIED TO 2 "FINANCIAL" MEASURES AND COMPENSATION TIED TO 3 "OPERATIONAL" MEASURES; AND THE BENEFITS OF COST 4 CONTROL. PROFITABILITY, AND STOCK PRICE MEASURES 5 Q. DO YOU AGREE WITH THE OPINION THAT INCENTIVE 6 COMPENSATION LINKED TO WHAT THE COMMISSION HAS TERMED 7 "FINANCIAL MEASURES" DOES NOT PROVIDE DIRECT BENEFITS TO 8 CUSTOMERS? 9 A. No. Based on its previous rulings, the Commission appears to be 10 categorizing as "financial" all incentive performance measures that have 11 been labeled as such by the utility and that are based on dollar amounts. 12 These include not only measures such as earnings per share, but also 13 measures designed to promote cost containment. 1 In reading these 14 decisions and the debates among the parties discussed therein, much of 15 the discussion seems to take it as given that incentives linked to financial 16 (or dollar-based) measures, regardless of their specific characteristics, do 17 not benefit customers. As a result, the competing viewpoints reflected in 18 these decisions seem to address mainly whether to label particular 19 measures as operational or financial. 2 20 Instead of focusing on whether a particular measure is dollar-based 21 or not - and therefore, whether incentives linked to that measure are 22 "financial" or "operational" based on the above dichotomy - I think it is For example, see PUC Docket No. 28840, PFD at 78. 2 For example, see PUC Docket No. 35717, PFD at 98. 2009 ETI Rate Case 4-366 Entergy Texas, Inc. Page 9 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case { 1 more worthwhile to return to the primary question: whether specific 2 incentives linked to dollar-based measures (including cost control, 3 profitability, and stock prices) are of benefit to customers. 4 5 Q. WHY WOULD INCENTIVE COMPENSATION LINKED TO COST 6 CONTROL, PROFITABILITY, AND STOCK PRICE MEASURES BE OF 7 DIRECT BENEFIT TO CUSTOMERS? 8 A. This is the case because these measures provide a necessary and 9 important incentive to managers to improve service and control costs. 10 Perhaps the easiest example of a dollar-based measure that could be 11 used in an incentive compensation plan that would benefit customers 12 directly is cost containment. As an example, consider an incentive 13 compensation plan that pays corporate managers an incentive award if 14 costs are suitably contained. On the one hand, such an incentive is likely 15 to benefit shareholders to some extent - managers who work under such 16 a compensation plan will work to control costs in order to achieve their 17 incentive compensation, and to the extent that they are successful, the 18 company will generate greater profits, benefiting shareholders. But 19 customers also directly benefit, because the company has lower costs, 20 and through the regulatory process, customers will ultimately pay lower 21 rates than they otherwise would have paid in the absence of such cost 22 controls. 2009 ETI Rate Case 4-367 Entergy Texas, Inc. Page 10 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 Q. WHAT IS THE ROLE OF THE REGULATORY PROCESS IN ENSURING 2 THAT INCENTIVES LINKED TO COST CONTROL BENEFIT 3 CUSTOMERS? 4 A. To understand the role of the regulatory process in linking cost control to 5 customer benefit, first consider an extreme example where there is no 6 regulatory lag and rates adjust instantaneously so that any change in a 7 utility's costs is immediately passed through to customers. In this case, a 8 cost-containment incentive clearly directly benefits customers and does 9 not benefit shareholders at all because customers reap the entire benefit 10 of any cost-saving innovations. In the other extreme, if rates never adjust 11 to changes in costs, then a cost-containment incentive benefits 12 shareholders but not customers. Thus, the regulatory process plays the 13 critical role of sharing the gairis from cost controls brought about by 14 managerial incentive compensation between customers and shareholders. 15 16 Q. IS THIS POINT THAT CUSTOMERS BENEFIT FROM MANAGERIAL 17 EFFICIENCY A COMMONLY ACCEPTED TENANT OF UTILITY RATE 18 ECONOMICS? 19 A. Yes. This idea of a win-win scenario, where both shareholders and 20 customers benefit from managerial efficiency, is not new and is a core 21 idea at the heart of well-established principles of regulatory economics. 22 For example, James C. Bonbright discusses it in his seminal 1961 treatise 23 on utility economics, Principles of Public Utility Rates. He notes that a 2009 ETI Rate Case 4-368 Entergy Texas, Inc. Page 11of28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case ( 1 potential drawback to regulated rates based on cost-plus-return pricing is 2 that it could discourage managerial efficiency because the firm would earn 3 little to no greater return after an efficiency gain because of a resultant 4 change in rates. He goes on to say that regulatory lag can help resolve 5 this problem, for the reasons discussed above. From his discussion, it 6 follows naturally that incentive compensation that links managerial 7 compensation to cost savings would likely be of benefit to customers. 8 9 Q. DO THESE PRINCIPLES APPLY TO OTHER FORMS OF INCENTIVE 10 COMPENSATION THAT ARE LINKED TO PROFITABILITY AND STOCK 11 PRICE MEASURES? 12 A. Yes. While I think that cost containment measures are the most obvious 13 example of incentives that have in some past PUCT cases been 14 categorized as "financial" and yet directly benefit customers, these 15 principles apply to other dollar-based or financial measures as well, such 16 as incentive awards tied to corporate profitability and stock prices. 17 18 Q. CAN YOU PLEASE FURTHER ELABORATE ON WHY CUSTOMERS 19 ARE LIKELY TO BENEFIT FROM COMPENSATION THAT IS LINKED 20 TO PROFITABILITY? 21 A. Yes. There is a direct link between cost containment and company 22 earnings, especially for a regulated utility. Managers with an incentive to 23 increase earnings will focus on controlling or cutting costs in a regulated 2009 ETI Rate Case 4-369 Entergy Texas, Inc. Page 12 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case ( 1 industry because it is more difficult to grow revenues. Additionally, the 2 same type of reasoning that supports a linkage between cost containment 3 and customer benefit also applies to incentive measures that focus on 4 containing capital expenditures. If managers can offer the same service 5 while cutting back on capital expenditures by investing more efficiently, 6 then shareholders benefit due to greater short-run cash flows for the 7 company, and customers benefit through the regulatory process through 8 lower recovery for the cost of capital due to a lower capital base. 9 10 Q. WHAT TYPE OF INCENTIVE COMPENSATION DO YOU INCLUDE 11 WITHIN THE CATEGORY OF COMPENSATION THAT IS LINKED TO 12 STOCK PRICES? 13 A. This category would include most long-term incentive plans (including 14 ETl's) that use performance units that are based on stock prices, as well 15 as stock options. 16 17 Q. CAN YOU BRIEFLY SUMMARIZE WHY YOU BELIEVE THAT 18 COMPENSATION THAT IS LINKED TO STOCK PRICES BENEFITS 19 CUSTOMERS? 20 A. Compensation that is linked to stock prices has several advantages for 21 customers as long as it is part of a reasonable, well-designed 22 compensation plan - in other words, as long as the total level of 23 compensation is reasonable compared to the market for similar positions 2009 ETI Rate Case 4-370 Entergy Texas, Inc. Page 13 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 and the form of compensation is well balanced across dollar-based and 2 non-dollar-based measures. First, compensation that is linked to stock 3 prices helps ensure that managers will consider the financial health of the 4 company when they make decisions, and it is in customers' interests to 5 have the company continue to be financially healthy. Second, 6 stock-based compensation provides an incentive for managers and 7 employees to ensure that the company operates efficiently, and via the 8 regulatory process, lower costs result in lower rates than would otherwise 9 occur. Third, stock-based compensation provides a monitoring 10 mechanism for managerial decision making and the overall quality of 11 management. Fourth, there is an interaction between these effects, as the 12 capital markets will tend to reward efficient long-term investments or 13 capital expenditures that will also lead to lower costs for customers. 14 15 Q. DO THESE REASONS THAT COMPENSATION THAT IS LINKED TO 16 STOCK PRICES BENEFITS CUSTOMERS ALSO APPLY TO 17 COMPENSATION THAT IS LINKED TO COST CONTROL AND 18 PROFITABILITY? 19 A. In general, yes. Stock prices are driven in part by cost control and 20 profitability, so to the extent that managers have an incentive to increase 21 the stock price, they will also have an incentive to control costs and 22 increase profits and cash flows, and vice versa. Of the reasons listed in 23 the previous answer, the first two reasons - incentives to ensure that the 2009 ETI Rate Case 4-371 Entergy Texas, Inc. Page 14 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 company is financially healthy and that it operates efficiently - are the 2 ones that are most closely shared by compensation based on cost control 3 and profitability. 4 5 Q. STARTING WITH THE FIRST REASON YOU MENTIONED, WHY DOES 6 COMPENSATION THAT IS LINKED TO PROFITABILITY AND STOCK 7 PRICES BENEFIT CUSTOMERS BY IMPROVING A COMPANY'S 8 FINANCIAL HEALTH? 9 A. If compensation that is linked to profitability and stock prices gives 10 managers an incentive to increase their company's earnings, cash flows, 11 and stock price, then this will also provide them with an incentive to 12 ensure that the company remains financially healthy. Stock prices of firms 13 that are in poor financial condition - for example, that have high debt 14 relative to the value of their assets - tend to be lower, all else being equal. 15 Similarly, firms in poor financial condition tend to have lower earnings and 16 operating cash flows. A stronger financial condition will also benefit 17 customers. If a company maintains a financially healthy position, it will 18 tend to have a lower cost of capital that will in turn benefit customers 19 through lower rates. For a discussion of this effect, see Chapter 15 of 20 Investment Valuation, by Aswath Damodaran. 3 In addition, the costs of 21 doing business with suppliers (of both goods and services, including labor) 3 ASWATH DAMODARAN, INVESTMENT VALUATION (John Wiley & Sons, 2d ed. 2002). 2009 ETI Rate Case 4-372 Entergy Texas , Inc. Page 15 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case ( 1 will remain lower. For example, if a company was not in a financially 2 stable condition, suppliers would tend to demand higher prices or more 3 onerous credit terms, resulting in higher costs that would lead to higher 4 rates than would otherwise occur. These are often termed "indirect costs 5 of financial distress," and are a commonly accepted concept in finance 6 that is supported by empirical evidence as I discuss further below. 7 8 Q. CAN YOU FURTHER EXPLAIN HOW INCENTIVE COMPENSATION 9 THAT IS LINKED TO PROFITABILITY AND STOCK PRICES CAN TEND 10 TO LEAD TO LOWER COSTS FOR CUSTOMERS? 11 A. The first step is to understand that compensation linked to profitability and 12 stock prices will provide managers with an incentive to operate efficiently 13 because, by doing so, a company's profitability (including earnings and 14 cash flow) and stock price will be higher than it would otherwise be. To 15 increase stock price, management tries to maximize the present value of a 16 company's expected cash flows by minimizing expenses and the cost of 17 capital. The role of incentive compensation in motivating managers to 18 minimize the cost of capital component and the associated benefits to 19 customers were discussed earlier. A second channel provided by 20 incentive compensation that can benefit customers is the incentive to 21 maximize the company's cash flows. In a regulated environment, 22 particularly one in which promotion of sales growth is discouraged, it is ( \ 23 likely to be more difficult to increase cash flows or profits by growing 2009 ETI Rate Case 4-373 Entergy Texas, Inc. Page 16 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 revenues, so management will tend to focus on efficient operations and 2 investment. 3 These lower costs will benefit shareholders in the short run, but 4 customers over the long run. This is due to the regulatory process that 5 directly links operating costs to rates. In fact, it is my understanding that 6 the Formula Rate Plan proposed in this case provides for an even more 7 direct link between cost savings and rates due to the frequency of reviews 8 and reflection of any identified cost savings in customer rates. This 9 channel is similar to the discussion earlier as to why incentive 10 compensation that is based on cost controls will tend to benefit customers. 11 12 Q. HOW DOES COMPENSATION THAT IS LINKED TO STOCK PRICES 13 BENEFIT CUSTOMERS VIA THE MONITORING OF MANAGERIAL 14 DECISIONS? 15 A. One of the functions of the stock market and its various participants is to 16 monitor companies' management. In their efforts to properly value stocks, 17 analysts, portfolio managers, and traders follow companies and 18 continually assess the various decisions, announcements, and pieces of 19 information they produce. In doing so, they act as a monitoring device, 20 ensuring that poor decisions would be punished by a falling stock price, so 21 managers have incentives to invest the shareholders' financial resources 22 efficiently. In this manner, managers help keep customers' costs lower 23 than they might otherwise be in the absence of such monitoring, and 2009 ETI Rate Case 4-374 Entergy Texas, Inc. Page 17 of 28 Direct Testimony of Jay C . Hartzell, PhD. 2009 Rate Case 1 improve the overall quality of service. An example of such evidence, cited 2 in one study, shows that institutional investors can help ensure that 3 management does not act myopically to cut research and development 4 expenditures in order to meet short-term earnings targets. 4 5 6 Q. HOW DO THESE INVESTMENT AND COST EFFECTS INTERACT DUE 7 TO THE STOCK MARKET? 8 A. An important role for stock-based compensation is to encourage 9 managers to refrain from sacrificing long-run success in pursuit of 10 short-term profit. 5 Stock prices are based not just on a company's 11 performance in the current year, but also on the market's expectations 12 about a company's future performance over many years. This ensures 13 that good investments tend to increase stock prices, even though those 14 investments use cash today in order to produce greater cash flows in the 15 future. This is a critical advantage of stock-based compensation over 16 annual incentive plans that are based on a particular year's (or a few 17 years') performance. Stock-based .compensation can help overcome 18 managerial myopia and provide managers with an incentive to make 19 efficient, long-term investments that benefit both customers (due to 4 Brian J. Bushee, The Influence of Institutional Investors on Myopic R&D Investment Behavior, 73 THE ACCOUNTING REVIEW, 3 at 305-333 (July 1998). 5 For example, see M.P. Narayanan, Form of Compensation and Managerial Decision Horizon, 31 JOURNAL OF FINANCIAL AND QUANTITATIVE ANALYSIS, 4 at 467-491 (1996). 2009 ETI Rate Case 4-375 Entergy Texas, Inc. Page 18 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case ( 1 efficient investments that lead to lower costs) and shareholders (due to 2 higher cash flows). In this case, the testimony of Company witnesses 3 Joseph F. Domino and Chris E. Barrilleaux addressing the Company's 4 expected future capital investments, and that of Company witness Robert 5 R. Cooper regarding long-term resource planning, provide examples of 6 such consideration. 7 8 IV. COSTS TO CUSTOMERS OF DISCOURAGING THE USE OF 9 INCENTIVE COMPENSATION THAT IS LINKED TO COST CONTROL, 10 PROFITABILITY AND STOCK PRICES 11 Q. WHILE YOUR EARLIER TESTIMONY DISCUSSED THE BENEFITS TO 12 CUSTOMERS OF USING INCENTIVE COMPENSATION THAT IS 13 LINKED TO COST CONTROL, PROFITABILITY AND STOCK PRICES, 14 ARE THERE ALSO NEGATIVE IMPACTS TO CUSTOMERS OF NOT 15 USING STOCK-BASED COMPENSATION? 16 A. Yes. In my opinion customers would be adversely affected if ETI did not 17 include such incentive compensation. in its overall compensation policy. 18 19 Q. STARTING WITH AN EXTREME EXAMPLE OF A COMPENSATION 20 POLICY WHERE ALL EMPLOYEES WERE ONLY PAID WITH 21 SALARIES, CAN YOU HIGHLIGHT THE IMPACT TO CUSTOMERS OF 22 SUCH A POLICY? 23 A. Yes. First, it is useful to note that if employees did not receive any 24 incentive compensation, salaries would have to be much higher in order to 2009 ETI Rate Case 4-376 Entergy Texas, Inc. Page 19 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case attract and retain the same quality of talent. Second, costs would likely rise and employee performance would likely suffer, as it would be difficult to effectively and efficiently motivate employees to take actions that would benefit shareholders and customers. In my opinion, customers would be worse off under such a policy. This is supported by the principle that individuals respond to incentives (a basic tenet of economics), and by empirical work that shows workers' output responds to the institution of an incentive plan.6 WOULD CUSTOMER INTERESTS BE ADVERSELY AFFECTED IF A COMPANY USED SALARY AND INCENTIVES LINKED TO MEASURES THAT HAVE BEEN TERMED "OPERATIONAL" ONLY? IN OTHER WORDS, IF THEY PROVIDED. SALARY AND INCENTIVES BASED ON MEASURES LIKE RELIABILITY AND SAFETY, BUT NO INCENTIVES BASED ON COST CONTROL, PROFITABILITY AND STOCK PRICES? Yes. I believe customers would be worse off under such a compensation policy. On the one hand, incentives linked to what have beP.n termed "operational" measures can improve customer welfare because the company can better attract, motivate and reta in talented employees. Compared to the hypothetical case where a company compensates its employees with salary only, by using salary and incentives linked to, for 6 ( Edward P. Lazear, Performance Pay and Productivity, 90 THE AMERICAN ECONOMIC REVIEW, at 1346-1361 (December 2000 ). 2009 ETI R ate Case 4-377 Entergy Texas, Inc. Page 20 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 example, safety or reliability, the company can pay less in salary and use 2 the associated savings to contribute to the annual incentive plans. On the 3 other hand, such a compensation plan still has substantial problems in the 4 context of customer benefits. 5 First, there is still no free lunch - employees' salaries and incentive 6 payments linked to operational incentives would have to be larger than 7 they otherwise would be if the firm also offered incentive compensation 8 linked to cost control, profitability and stock prices in order for the firm to 9 compete in the market for labor. Second, such a compensation plan 1O would not provide any incentives for employees and managers to control 11 costs. If employees only had incentives to improve non-cash measures of 12 performance, such as safety and reliability, then they would likely 13 over-invest in these measures relative to what customers might prefer, at 14 the expense of alternative investments that would produce lower costs for 15 customers. For example, if management only had incentives based on 16 wait times when customers called with questions or complaints (plus a 17 base salary), then they would have an incentive to hire enough staff such 18 that customers never had to wait if they called to ask a question. 19 However, if you left it up to customers , they would likely view it as 20 worthwhile to run the risk of having to wait for a little while on rare 21 occasions if it meant that their service was provided at a lower cost and 22 those cost savings were passed along to customers through the regulatory 23 process. 2009 ETI Rate Case 4-378 Entergy Texas, Inc. Page 21of28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case I ( 1 Third, a compensation plan consisting of salary and incentives 2 based solely on annual measures of operational performance could likely 3 lead to "horizon problems." By horizon problems, I mean that managers 4 tend to have a natural tendency, absent incentives, to focus on the short 5 run at the expense of the long run. Stock prices by their nature are 6 forward looking. Taken together, a compensation plan that included 7 incentives based on annual measures such as reliability and customer 8 satisfaction, but not incentives based on cost controls, profitability and 9 especially stock prices, could provide incentives for managers to maximize 10 their immediate compensation at the expense of longer-run benefits that 11 the customer could have enjoyed. 7 12 For example, consider a manager facing a decision whether to hire 13 additional staff to answer phones in a call center (and bring down phone 14 wait times) or to invest the same amount in a capital investment to put in 15 place a new, more centralized call center that would produce significantly 16 lower costs several years in the future. If the manager is paid purely in 17 cash compensation including an incentive payment based on current-year 18 customer satisfaction surveys (that would include phone wait times), then 19 the manager would be more likely to forgo the long-term investment 20 project and increase payroll by hiring additional employees in order to 21 maximize his or her incentive pay by implementing the short-term solution 7 See M.P. Narayanan, Form of Compensation and Managerial Decision Horizon, 31 JOURNAL (, ' OF FINANCIAL AND QUANTITATIVE ANALYSIS, 4 at 467-491 (1996). 2009 ETI Rate Case 4-379 Entergy Texas, Inc. Page 22 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 today. But, at some point, customers are better off by having slightly 2 longer waits on the phone now but reaping the benefits of lower overall 3 costs in the future. A well-designed compensation plan that includes 4 incentives linked to both customer satisfaction (in this example) and cost 5 control, profitability and stock prices would provide incentives for the 6 manager in this example to properly consider the benefits of such a long- 7 term investment without sacrificing current customer satisfaction. 8 9 Q. HOW DOES THE INCLUSION OF INCENTIVE COMPENSATION THAT 10 IS LINKED TO COST CONTROLS, PROFITABILITY AND STOCK 11 PRICES HELP AVOID THESE NEGATIVE OUTCOMES FOR 12 CUSTOMERS? 13 A. If a company adds compensation that is linked to cost controls, 14 profitability, and stock prices to a compensation plan that includes base 15 salary and incentives based on non-cash based measures in a reasonable 16 way, customers are likely to be better off. Such incentive compensation 17 helps a company attract, motivate, and retain talented employees and 18 gives managers a reason to focus on the long run in addition to the current 19 year's performance, costs, customer service, and the like. 20 This focus on the longer run is evident in the design of ETl's LTIP 21 and stock option plan. For example, ETl's LTIP bases its payments in a 22 particular year on the achievement of goals over the previous three years, 23 encouraging managers to consider consistent and long-term success as 2009 ETI Rate Case 4-380 Entergy Texas, Inc. Page 23 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case ( 1 key objectives. Plus, options granted vest over a three-year period, 2 forcing managers to think about future years and how the firm will be 3 viewed several years into the future. The stock options also have a life of 4 ten years, which provides an additional incentive to focus on the long 5 term. Such a focus on maximizing stock price over a ten-year period is 6 beneficial for all stakeholders. As stock options may be awarded annually, 7 option grants present a rolling ten-year window for those employees who 8 receive them, reinforcing that long-term view. Finally, the provision that 9 requires senior managers to continue to hold stock received via exercising 10 option grants up to a multiple of their salary further encourages longer-run 11 thinking and incentive alignment, as managers cannot exercise all their 12 options for cash and be immune to declines in the firm's financial health. 13 14 V. RESPONSE TO COMMON ARGUMENTS AGAINST INCENTIVE 15 COMPENSATION LINKED TO COST CONTROL. PROFITABILITY AND 16 STOCK PRICES FROM THE CUSTOMERS' PERSPECTIVE 17 Q. HOW DO YOU RESPOND TO THE ARGUMENT THAT INCENTIVE 18 COMPENSATION THAT IS LINKED TO COST CONTROL, 19 PROFITABILITY, AND STOCK PRICES WILL BE DETRIMENTAL TO 20 CUSTOMERS BECAUSE IT WILL CAUSE MANAGERS TO CUT 21 CUSTOMER SERVICE-RELATED EXPENSES TO INCREASE 22 PROFITS? 23 A. This argument underscores the importance of a well-balanced 24 compensation plan. By including both incentives based on non-dollar 2009 ETI Rate Case 4-381 Entergy Texas, Inc. Page 24 of 28 Direct Testimony of Jay C. Hartzell, PhD . 2009 Rate Case ( 1 based measures such as customer service, reliability and safety, and 2 incentives based on cost control, profitability and stock price, as does ETI, 3 management will not want to cut one in order to increase the other, but will 4 instead look for balanced decisions that help both. 5 6 Q. IS THERE REASON TO BE CONCERNED FROM THE CUSTOMERS' 7 PERSPECTIVE BECAUSE STOCK PRICES AND PROFITS ARE 8 DRIVEN BY MANY OTHER FACTORS IN ADDITION TO 9 CONTROLLING COSTS, OR HAVING A LOW COST OF CAPITAL? 10 A. No. Avoiding this concern is why firms generally do not use compensation 11 plans that consist solely of stock- or profit-based incentive pay - to do so 12 would be too risky for the employees and would lead to larger overall 13 compensation expense because risk-averse individuals would demand 14 higher compensation levels in order to compensate them for bearing the 15 risk of such a hypothetical plan. This is also why stock- and profit-based 16 incentive compensation is more important at the top of the organization. 17 Senior management can more clearly see (and anticipate) the impact of 18 their actions on the firm's stock price, so stock-based compensation is a 19 more efficient compensation tool for this level of management. 2009 ETI Rate Case 4-382 Entergy Texas, Inc. Page 25 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case ( 1 VI. EMPIRICAL EVIDENCE SUPPORTING TESTIMONY 2 Q. ARE THE CONCEPTS IN SUPPORT OF THE CUSTOMER BENEFITS 3 OF INCENTIVE COMPENSATION SUPPORTED BY EMPIRICAL 4 EVIDENCE? 5 A. Yes. As I discuss below, there are multiple studies published in 6 peer-reviewed journals that report evidence that is consistent with my 7 testimony. 8 9 Q. IS THERE EMPIRICAL EVIDENCE THAT THE ADOPTION OF 10 INCENTIVE TARGETS BASED ON STOCK OR EARNINGS 11 PERFORMANCE BENEFITS CUSTOMERS? 12 A. Yes. There is a published study that examines the adoption of long-term 13 incentive plans that reward managers with stock or stock-based 14 compensation, where the stock grants are based on long-run profitability.8 15 The study finds that after the adoption of such plans, managerial 16 compensation is more closely linked to the interests of managers and 17 stakeholders, including customers. This is also consistent with the studies 18 I discuss below, such as one that links market value with customer 19 satisfaction. 8 ( Alka Arora and Pervaiz Alam, CEO Compensation and Stakeholders' Claims, <-.. 22 CONTEMPORARY ACCOUNTING RESEARCH, 3 at 519-547 (Fall 2005). 2009 ETI Rate Case 4-383 Entergy Texas, Inc. Page 26 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 Q. HOW DO OTHER EMPIRICAL STUDIES SUPPORT THE OPINION 2 THAT INCENTIVE COMPENSATION TIED TO STOCK OR 3 PROFITABILITY BENEFITS CUSTOMERS? 4 A. Earlier, I mentioned two empirical studies that provide support for my 5 opinion that stock-based incentive compensation provides benefits to 6 customers. The first study provides evidence of how the oversight of 7 companies' performance by stock-market participants can affect those 8 firms' investment behavior and curtail managerial myopia. 9 This is one of 9 the channels I discussed earlier by which the presence of stock-based 10 incentive compensation can benefit customers by encouraging managers 11 to focus beyond the short term and think about long-term efficient 12 investments. The second study shows that workers do respond to 13 incentive plans in a manner consistent with the intent behind the plans' 14 design. 10 Thus, if a company adopts a compensation plan that includes 15 incentives based on customer welfare and stock price, one can expect 16 managers to take actions to improve customer welfare and maximize 17 stock price (holding all else equal). 18 In addition, there is empirical evidence in the literature that firms 19 with higher market values tend to also have higher customer satisfaction, 20 supporting the conclusion that the goals of financial success and customer 9 Brian J. Bushee, The Influence of Institutional Investors on Myopic R&D Investment Behavior, 73 THE ACCOUNTING REVIEW, 3 at 305-333 (July 1998). 10 Edward P. Lazear, Performance Pay and Productivity, 90 THE AMERICAN ECONOMIC REVIEW, at 1346-1361 (December 2000). 2009 ETI Rate Case 4-384 Entergy Texas, Inc. Page 27 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case ( 1 satisfaction are interrelated. 11 This result has been shown for a broad 2 sample of firms, but also for utilities in particular. This empirical finding is 3 inconsistent with the idea that the most profitable or valuable firms 4 become that way by cutting customer service, and instead suggests that 5 there exists positive feedback between a firm's financial performance 6 (stock price) ·and customers' welfare, even in the utility industry. 7 Empirical evidence also exists that some firms hurt their financial 8 performance (stock price) by overinvesting in customer service.12 This 9 result suggests that including stock price in the compensation plan will 10 help ensure against myopic investments in short-term service that would 11 come at the expense of investments that would produce greater long-term 12 benefits to customers. It also points toward the conclusion that basing 13 incentive compensation for purposes of setting rates solely on operational 14 goals could well be harmful to customers' interests in the long run . 15 Finally, there is empirical evidence that firms with lower stock prices 16 (or that are less financially healthy) face higher costs and greater risks. 17 For example, some researchers have shown how less financially healthy 18 companies have trouble responding to external shocks, and face higher 19 costs of doing business (through higher wages or worse terms from 11 Christopher D. Ittner and David F. Larcker, Are Nonfinancial Measures Leading Indicators of Financial Performance? An Analysis of Customer Satisfaction, 36 JOURNAL OF ACCOUNTING RESEARCH, Supplement 1998 at 1 - 35. ( 12 Id. 2009 ETI Rate Case 4-385 Entergy Texas, Inc. Page 28 of 28 Direct Testimony of Jay C. Hartzell, PhD. 2009 Rate Case 1 suppliers, for example). 13 These results support yet another channel by 2 which stock-based incentive compensation should provide direct benefits 3 to customers. Stock-based incentive compensation encourages 4 managers to maintain a company's financial health, thus leading to more 5 efficient operations and greater cost control than would otherwise occur. 6 7 VII. CONCLUSION 8 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 9 A. Yes, at this time. 13 Chris Parsons and Sheridan Titman, Capital Structure and Corporate Strategy (January 2007). The article is available at http://ssrn.com/abstract=983553. 2009 ETI Rate Case 4-386 ~, :'., ·'; r f V ED .1,., it •• ., SOAH DOCKET NO. XXX-XX-XXXX zao~ FEB -9 PM 2: 21 PUC DOCKET NO. 28840 PUBLIC UTILIT y COMHISSION FILING CLERK APPLICATION OF AEP TEXAS § BEFORE THE STATE OFFICE CENTRAL COMPANY FOR § OF AUTHORITY TO CHANGE RATES § ADMINISTRATIVE HEARINGS REDACTED DIRECT TESTIMONY OF SARAH J. GOODFRIEND, PH.D. ON BEHALF OF CITIES SERVED BY AEP TEXAS CENTRAL COMPANY FEBRUARY 9, 2004 1 2 DIRECT TESTIMONY OF 3 SARAH J. GOODFRIEND, PH.D. 4 TABLE OF CONTENTS 5 6 SECTION PAGE 7 8 I. INTRODUCTION AND ORGANIZATION OF TESTIMONY ................................... 6 9 10 A. PRINCIPAL FINDINGS AND RECOMMENDATIONS ................................. 7 11 B. ORGANIZATION OF TESTIMONY ............................................................... 12 12 13 II. CUSTOMER SERVICE PROVIDED BY TCC TO THE 14 RETAIL MARKET ......................................................................................................... 12 15 16 A. STANDARD OF EVALUATION ....................................................................... 13 17 1. DESCRIPTION OF UNNECESSARY COSTS .................................... 13 18 2. PURA STANDARDS: WHEN UNNECESSARY 19 COSTS BECOME UNACCEPTABLE COSTS ................................... 15 20 3. PURA/ECONOMIC FRAMEWORK: THE 21 ALIGNMENT STANDARD ................................................................... 16 22 23 B. SURVEY DESCRIPTION AND RES UL TS ..................................................... 23 24 1. INTRODUCTION AND ORGANIZATION ......................................... 23 25 2. NUMERICAL RESULTS ....................................................................... 25 26 3. QUALITATIVE RESULTS .................................................................... 29 27 LACK OF RESPONSIVENESS TO REP INQUIRIES ....................... 30 28 NO EDUCATIONAL PROGRAMMING AND 29 OUTREACH TO REPS .......................................................................... 32 30 INACCURACIES AND UNRESPONSIVENESS 31 WORSEN MARKET PROBLEMS ....................................................... 35 32 BILLING AND INVOICING: FOUNDATIONS 33 FOR ERROR ............................................................................................ 46 34 SLOW OR NO GO ON FASTRAK RESOLUTIONS ......................... 56 35 36 c. REBUTTAL TO TCC WITNESSES GORDON AND HOOPER .................. 62 37 1. ISA SERVICE QUALITY ...................................................................... 62 38 SUMMARY FINDING ............................................................................ 62 39 WITNESS GORDON .............................................................................. 63 40 REPORTED PERFORMANCE FOR THE ISA .................................. 65 41 WITNESS HOOPER ............................................................................... 67 42 TCC REPORTED BILLING ACCURACY MEASURE ..................... 69 DIRECT TESTIMONY 2 GOODFRIEND 1 2. SERVICE QUALITY REPORTING: 2 RECOMMENDATION ........................................................................... 70 3 4 III. REQUEST FOR GOOD CAUSE EXCEPTION .......................................................... 71 5 6 A. NEITHER ABD O&M SERVICES NOR TRANSMISSION 7 CONSTRUCTION SERVICES COMPLY WITH SUBST. R. 8 §25.342(.t)(D) Orf HER SERVICE ....................................................................... 71 9 1. REGULATED UTILITY PROVISION OF 10 UNREGULATED SERVICES: DEFINITIONS 11 AND DISTINCTIONS ............................................................................. 71 12 LEGAL FRAMEWORK ......................................................................... 71 13 THE QUID PRO QUO IN RULE-COMPLIANT 14 OTHER SERVICE .................................................................................. 75 15 DEFINING "ESSENTIAL" FOR RULE-COMPLIANCE ................. 78 16 2. TCC HAS YET TO DEMONSTRATE COMPLIANCE 17 WITH THE OTHER SERVICE EXCEPTION .................................... 81 18 THIS IS A SITUATION OF FIRST IMPRESSION ............................ 81 19 INSTRUCTION TO CSW: NO ADDS SOLELY 20 FOR OTHER SERVICE ...................................................................•..... 83 21 TWO EXAMPLE VIOLATIONS AND RELATED 22 CROSS-SUBSIDIES ................................................................................ 84 23 THE EXTENT OF CROSS SUBSIDY .................................................. 87 24 PROBLEMS OF DETECTION .............................................................. 91 25 EVIDENCE OF ANTI-COMPETITIVE POTENTIAL ...................... 92 26 27 B. THE THIRD VIOLATION: TRANSMISSION CONSTRUCTION 28 SERVICE IS NOT AN ESSENTIAL TDSP SYSTEM SERVICE .................. 94 29 30 C. EFFECTS OF GRANTING A GOOD CAUSE EXCEPTION ........................96 31 32 IV. PROPOSED DISCRETIONARY SERVICE FEES .....................................................98 33 34 V. REQUEST FOR PRE-APPROVAL OF DEBT RECOVERY .................................. 108 35 36 VI. RATE CASE EXPENSES ............................................................................................. 113 37 38 APPENDIX A - Resume 39 40 EXHIBIT -SJG-1 Retail Electric Provider Survey DIRECT TESTIMONY 3 GOODFRIEND LIST OF ACRONYMS - TERMINOLOGY Associated Business Development, the category used by TCC to indicate ABD unregulated wholesale business activities AEP-CSW American Electric Power -- Central and South West BAO Billing and Accounting Operations ERCOT Electric Reliability Council of Texas ERCOT Published standards and requirements for all market participants Protocols ESI-ID A unique numerical identifier for each premise location in ERCOT ERCOT sponsored process for market participants to use in resolving FASTRAK electronic transaction-related problems in retail markets GAAP Generally Accepted Accounting Principles ISA Integrated Stipulation and Agreement IT Information Technology MAC SS Marketing And Customer Services System REP retail electric provider or competitive retailer RMS Retail Market Subcommittee ofERCOT TCE Texas Commercial Energy Texas Standard Electronic Transaction -- the market wide electronic standard Texas SET for electronic data interfacing (EDI) transactions DIRECT TESTIMONY 4 GOODFRIEND TNMP Texas New Mexico Power Company TXU Texas Utilities Electronic transaction whereby TDSP acknowledges a switch request to 814-04/05 ERCOT and ERCOT then sends the acknowledgement to the REP 867s, Electronic transactions containing initial, monthly or historical usage data 867series TABLE OF FIGURES 1. FIGURE!: RELATIVE RANK OF TCC AMONG ERCOT TDSPS 2. FIGURE 2: TCC GRADE DISTRIBUTION FROM REP SURVEY 3. FIGURE 3: RESPONSIVENESS TO REP INQUIRES 4. FIGURE 4: EDUCATIONAL PROGRAMMING AND OUTREACH 5. FIGURE 5: BUSINESS CASE CUSTOMER CHOICE OPERATIONS 6. FIGURE 6: RESPONSIVENESS IN RESOLVING MARKET PROBLEMS 7. FIGURE 7: METER READING ACCURACY 8. FIGURE 8: 550,000 ADDITIONAL ESTIMATED METER READS - POTENTIAL MARKET COSTS 9. FIGURE 9: TEXAS CENTRAL COMPANY COMPARISON OF PERCENT CANCELLED INVOICES [REDACTED TABLE] 10. FIGURE 10: RESPONSIVENESS IN RESOLYING FASTRAK PROBLEMS 11. FIGURE 11: ERCOT: 8678 RECEIVED ON CANCELED SERVICE ORDERS 12. FIGURE 12: POTENTIAL FOR CROSS-SUBSIDY OF WHOLESALE OPERATIONS BY RETAIL OPERATIONS (BY JOB TITLE) DIRECT TESTIMONY 5 GOODFRIEND 1 I. INTRODUCTION AND ORGANIZATION OF TESTIMONY 2 3 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 4 A. My name is Sarah Goodfriend and my business address is 1500 West 24th Street, 5 Austin, Texas 78703. 6 Q. BRIEFLY DESCRIBE YOUR EXPERIENCE AND QUALIFICATIONS 7 RELEVANT TO THIS PROCEEDING. 8 A. As an economic consultant specializing in competition and regulatory policy issues, I 9 have twenty-five years of experience in the regulated electric utility and 10 telecommunications industries. Prior to entering graduate school, I was employed as 11 an economist by the Public Utility Commission of Texas ("PUCT"). In 1983, I 12 worked for Carolina Power And Light Company, receiving a Ph.D. in economics 13 from the University of North Carolina at Chapel Hill in 1985. Since that time, I have 14 worked and testified on behalf of the Economic Policy Office of the Federal Energy 15 Regulatory Commission and the Bureau of Economics of the Federal Trade 16 Commission. I returned to the PUCT in 1992 to create an Office of Economic Policy 17 and was appointed a PUC Commissioner in 1993, serving until 1995. Before starting 18 my consulting practice, I joined the Washington D.C. office of MCI 19 Telecommunications Corporation where I was responsible for policy development 20 and providing expert witness testimony. I have been an independent consultant since 21 1997. 22 As an independent consultant, I provided expert testimony on behalf of South 23 Texas Electric Cooperative and a Central Power and Light Wholesale Customer 24 group in the AEP-CSW merger proceedings. Since then, as my resume shows, I have DIRECT TESTIMONY 6 GOODFRIEND 1 remained active as an advisor or testifying witness on behalf of various market 2 participants in the electric utility and telecommunications industries. Most recently, I 3 have worked as an advisor to a group of Retail Electric Providers ("REPs") pursuant 4 to their participation in the Texas Nodal Team stakeholder meetings. Some of these 5 REPs are active in the TCC service territory. 6 Q. ON WHOSE BEHALF ARE YOU PROVIDING THIS TESTIMONY? 7 A. I have been retained by Cities served by AEP Texas Central Company ("Cities"). 8 AEP Texas Central Company ("TCC") is the monopoly TDSP for these Cities in their 9 role as market participants, end-use customers and ratepayers. 10 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 11 A. Cities desire that the rates and operations of TCC not hinder the development of a 12 competitive market. Cities' experience with the deregulated market has not been 13 good. I have been asked to identify cross-subsidies, anti-competitive behavior and 14 areas where improvements to quality of service can be made. My testimony evaluates 15 TCC's (1) quality of service to retail customers, (2) request for good cause exception 16 Subst. R. §25.342(f)(D), (3) proposed discretionary service fees and (4) request for 17 pre-approval for recovery of REP bad debt expense. 18 A. PRINCIPAL FINDINGS AND RECOMMENDATIONS 19 Q. WHAT ARE YOUR PRINCIPAL FINDINGS? 20 A. My testimony reaches these principal findings: 21 1. The quality of service that TCC is providing to REPs, end-use customers and 22 the market is unacceptable and contrary to provisions of the Public Utility Regulatory 23 Act ("PURA"). DIRECT TESTIMONY 7 GOODFRIEND 1 2. The structure of TCC costs supports difficult to detect cross-subsidy of 2 wholesale operations by using and placing retail ratepayer dollars at risk. 3 3. TCC's request for a good cause exception to the PUCT's Electric Business 4 Separation Subst. R. § 25.342(f)(D) Other Service would permit greater 5 circumvention of the PUCT's Unbundling Rules than now exists. 6 4. Transmission Construction Services and Associated Business Development 7 ("ABD") Operation and Maintenance ("O&M") Services are the two categories of 8 service that TCC offers pursuant to the Other Service exception. Neither class of 9 service complies with the requirements of Subst. R. § 25.342(f)(D)(i). 10 5. TCC's Transmission Construction Service is principally supplied using 11 personnel non-essential to T&D system operations. To avoid future cross-subsidies, 12 TCC's best course of action is to create a stand-alone Construction Services operation 13 separate from the regulated utility business. 14 6. TCC's non-compliance with requirements of Subst. R. § 25.342(f)(D) Other 15 service is consistent with evidence of high Administrative and General expense but 16 declining staffing/resources for retail operations that Dr. Patton finds and is also a 17 likely reason for the poor service quality for regulated retail operations that Dr. Patton 18 and I find. 19 7. Various changes need to be made to TCC's proposed Discretionary Service 20 Tariff fees, terms and conditions to improve service quality and better align TCC's 21 tariff offerings with market needs. 22 8. TCC's request for pre-approval for deferral and inclusion of any REP bad debt 23 expense is premature and contrary to policy. DIRECT TESTIMONY 8 GOODFRIEND 1 Q. WHAT ARE YOUR PRINCIPAL RECOMMENDATIONS? 2 A. I recommend the Commission: 3 1. Adopt a rate of return recommendation consistent with the requirements of 4 PURA Sec.36.052 to recognize the poor quality of services TCC now provides. 5 2. Direct TCC to return to the lower level of estimated meter readings it reported 6 for each customer class prior to the inception of the retail Choice Pilot project. 7 3. Deny TCC's request for a good cause waiver of Subst. R. 8 § 25.342(f)(D)(ii)(III) Other services. Thus, The Commission should direct TCC to 9 apply the $2,542,584.341 profit TCC has failed to record as a revenue credit in this 10 proceeding to reduce the total revenue requirement in this case. 2 11 4. Immediately place a moratorium on TCC's acceptance of new Transmission 12 Construction contracts. The moratorium should not be lifted until (a) TCC 13 demonstrates compliance with Subst. R. §25.342(f)(D) Other service, or, as a 14 preferred alternative, (b) separates Transmission Construction Services completely 15 from unregulated utility operations in ERCOT. 16 5. Immediately place a moratorium on TCC's acceptance of new ABD O&M 17 contracts until (a) TCC demonstrates compliance with Subst. R§ 25.342(f)(D) Other 18 Service and (b) TCC implements the REP-survey recommendations listed below. 19 6. Direct TCC to implement the following changes to its Discretionary Service 20 tariff fees, terms and conditions: I Profit from Updated Response to Cities 17-14, provided in Workpapers. 2 Response to Staff BA 1-5. Margins received from third-party contracts for transmission services were booked to FERC Account No. 417-Revenues from Non-utility operations. DIRECT TESTIMONY 9 GOODFRIEND I a) 6.1.2.1.8 Inaccessible Meter Fee should remain a Denial of Access to 2 Meter Fee. TCC should retain responsibility to document, upon request, 3 customer denial of access. 4 b) 6.1.2.1.6 Special Meter Reading Fee should not be charged when a REP 5 requests an actual meter re~d on an outstanding bill with estimated usage. 6 c) An Account History Fee should not be charged to end-users, REPs or 7 aggregators of record. 3 8 d) 6.1.2.1.13 Copying Fee, 6.1.2.15 Special Products/Service Fee or other fee 9 may not be charged as a substitute for the Account History Fee. 10 e) 6.1.2.1.16 Special Billing Services Fee, 6.1.2.1.13 Copy Fee or 6.1.2.15 11 Special Products/Service Fee shall not be charged to REPs or aggregators 12 requesting a Detailed Billing and Invoicing Analysis. 13 f) TCC's terms and conditions are not in compliance with Consumer 14 Protection Rules as proposed. TCC should be directed to conform its tariff 15 to the rule adopted in Docket No. 27084. 16 7. Deny TCC's request to defer any bad debt expense incurred in providing 17 service to REPs and deny TCC's request for grant of authority in this rate proceeding 18 to include such costs in TCC's next base rate case. 19 8. Direct TCC to file as non-confidential the "B Report" portion of TCC's 20 Quarterly Performance Report that ERCOT now files confidentially on behalf of 21 TCC. 3 The Account History Fee does not appear in the tariff as a proposed or existing discretionary service and so has no tariff reference number. DIRECT TESTIMONY 10 GOODFRIEND 1 Q. PLEASE PROVIDE THE LIST OF REP-SURVEY RECOMMENDATIONS 2 YOU REFER TO IN YOUR FIFTH RECOMMENDATION ABOVE. 3 A. The list is: 4 • Increase dedicated resources and reorganize job responsibilities so each REP has 5 a dedicated REP relations person. (Now there is one person "dedicated" to all 6 REPs). 7 • Create and apply job performance metrics to reward job performance relating to 8 REP satisfaction. 9 • At no charge, prepare a Detailed Billing and Invoicing Analysis for different 10 classes of meters and services for each REP or aggregator that requests it.4 11 • Schedule and offer at least one face-to-face meeting between REPs and their 12 customer service representatives annually. 13 • Provide current usage information to aggregators upon request for all active 14 premise locations ("ESI-IDs") that have provided a letter of authorization for their 15 usage information to be released to the aggregator. 16 • Annually perform an anonymous Customer Satisfaction Survey for REPs and 17 aggregators.5 18 • Provide Commission staff with a software and staffing improvement plan 19 identifying timetables, targets and budgets for Customer Service business and 4 Alternatively, TCC should produce a manual of information necessary for the REP/aggregator to perform detailed analysis. A Detailed Billing and Invoicing Analysis includes the breakout and definition of each charge type which underlies any composite charge provided, so that the bill or invoice may be readily understood and interpreted. 5 The survey should be modeled on the anonymous telephone survey now being performed by CenterPoint TDSP for REPs. Perform this survey until granted waiver of this requirement by the Commission. File the results publicly with the Commission. DIRECT TESTIMONY 11 GOODFRIEND 1 related Information Technology operations to improve TCC's performance with 2 protocols and other measures of quality of service discussed here. 3 Q. HOW ARE YOUR RECOMMENDATIONS RELATED TO YOUR 4 FINDINGS? 5 A. My recommendations lay out what is necessary for the PUCT to do in this proceeding 6 to (1) gain control over the unnecessary costs that TCC is imposing on the ERCOT 7 market by providing poor service quality at retail and (2) eliminate the cross-subsidies 8 of wholesale operations that TCC is providing from retail ratepayers. 9 B. ORGANIZATION OF TESTIMONY 10 Q. HOW IS YOUR TESTIMONY ORGANIZED? 11 A. This concludes Section I, Principal Findings and Recommendations. In Section II, I 12 evaluate the Customer Service TCC provides to the retail market. Section III 13 addresses TCC's request for good cause exception to §25.342(f)(D)(ii)(III) and 14 includes compliance issues related to TCC's provision of unregulated wholesale 15 service. Section IV addresses TCC's proposed discretionary service fees and Section 16 V addresses TCC's request for certain treatment of REP bad debt expense. The 17 testimony concludes with support for rate case expenses in Section VI. 18 II. CUSTOMER SERVICE PROVIDED BY TCC TO THE RETAIL MARKET 19 Q. WHAT ARE YOUR FINDINGS? 20 A. (1) AEP has unnecessarily imposed significant costs on the market, on market 21 participants, and thereby, on the quality of service the market delivers to end use 22 customers. DIRECT TESTIMONY 12 GOODFRIEND 1 (2) AEP lacks concern for TCC's retail customers. This lack of concern results in 2 missed opportunities to improve market performance at little or no cost to TCC. 3 (3) AEP management understaffs and undersupports TCC customer service functions 4 necessary for market development and for the delivery of acceptable service quality 5 to end users. 6 (4) Without regulatory action in this proceeding, TCC will continue to provide a case 7 study in how TDSP interests fail to align with market needs. 8 A. STANDARDOFEVALUATION 9 1. DESCRIPTION OF UNNECESSARY COSTS 10 Q. WHAT DO YOU MEAN BY "UNNECESSARY COSTS"? 11 A. Unnecessary costs are costs imposed when a TDSP fails to perform acceptably in all 12 dimensions of service: (1) quality and timeliness of communication, (2) speed of 13 response, (3) pro-active problem solving, (4) dedication of resources and (5) accuracy 14 of response. When any one of these dimensions of service deteriorates, the customer 15 begins to experience unnecessary costs of doing business. Said differently, a TDSP 16 that is able to excel in these performance areas is contributing to minimizing the costs 17 of doing business in the market, and probably minimizing its own long-term costs of 18 providing customer service as well. End-use customers are the ultimate beneficiaries 19 when a TDSP is performing acceptably in all dimensions of service, thereby avoiding 20 unnecessary costs to market participants and consumers. DIRECT TESTIMONY 13 GOODFRIEND 1 Q. HOW ARE END-USE CUSTOMERS HARMED BY UNNECESSARY COSTS? 2 A. Customers are harmed in three ways: 3 First, a customer suffers directly from unnecessary delay and inaccuracy. A delayed 4 bill means the customer cannot budget or exercise control over electricity costs. 5 Second, customers are harmed by prices higher than they need to be. And, third, 6 customers are harmed because it is not rational for REPs to market, develop a 7 reputation or differentiate their products on the basis of service quality. 8 Q. WHY ARE PRICES HIGHER THAN THEY NEED TO BE? 9 A. There are two paths by which prices to end-use customers increase. Economists 10 understand that in competitive markets, any increase in a suppliers' cost of doing 11 business must ultimately lead to a price increase. Unnecessary costs increase the 12 REP's cost of doing business. Because REPs must ultimately pass along service costs 13 imposed by an inefficient TDSP to end use customers, these unnecessary costs can be 14 thought of as an implicit or hidden tax on REPs, and ultimately on end-use customers. 15 Q. WHAT IS THE SECOND PATH TO HIGHER PRICES? 16 A. By raising all REPs' cost structures, unnecessary costs operate as an implicit 17 reduction in headroom. This understanding is why the Commission has been 18 concerned since before the onset of Customer Choice with "headroom". The 19 reduction in headroom is the second path whereby unnecessary costs result in a price 20 increase to end users. A reduction in headroom can limit entry or force market exit of 21 otherwise worthy suppliers. In tum, this tends to raise prices to end-users by limiting 22 the size, number or extent of diversity among suppliers. DIRECT TESTIMONY 14 GOODFRIEND 1 Q. WHAT IS THE PROBLEM CREATED FOR RETAIL SERVICE QUALITY? 2 A. With Customer Choice, REPs have become the closest link to customers for 3 enrollment, billing, and customer care services. Yet, the quality of service the REP 4 can provide can be no better than what the REP receives upstream from ERCOT or 5 the monopoly TDSPs. Thus, it makes no sense for REPs interested in differentiating 6 their service from their peers on the basis of superior service quality to invest in 7 resources that would allow them to do so, until risks associated with TDSP service 8 quality are controllable. This important dimension of REP competition cannot take 9 root without reliably acceptable upstream service quality from TDSPs and ERCOT. 10 2. PURA STANDARDS: WHEN UNNECESSARY COSTS 11 BECOME UNACCEPTABLE COSTS 12 13 Q. WHAT PURA STANDARDS ARE INSTRUCTIVE FOR AN ASSESSMENT 14 OF RETAIL SERVICE QUALITY? 15 A. First, PURA provides some qualitative standards for assessing service quality. For 16 example, Sec. 38.022 recognizes that an electric utility may not engage in a practice 17 that tends to restrict or impair competition. As just discussed, poor TDSP service 18 quality is such a practice in the context of an emerging competitive market. 19 Second, within the Customer Safeguards for Retail Competition section, 20 (PURA Sec. 39.101), the Commission must establish customer protection standards 21 that entitle customers to, among other things, bills presented in a clear format and in 22 language understandable by customers; accuracy of metering and billing; and other 23 information or protections necessary to ensure high-quality service to customers. The 24 customer is also entitled to prompt resolution of disputes with its chosen REP and 25 TDSP. DIRECT TESTIMONY 15 GOODFRIEND 1 PURA recognizes the tendency of suppliers to deteriorate service quality as a 2 method of cost-cutting and so provides for the assessment of civil and administrative 3 penalties to enforce customer safeguards. 4 Q. DOES PURA PROVIDE OTHER STANDARDS? 5 A. Yes, PURA prohibits service from deteriorating relative to standards established 6 under integrated utility operation. PURA directs the PUCT to modify its current 7 customer protection rules on or before June 30, 2001 "to ensure at least the same level 8 of customer protection against potential abuses and the same quality of service that 9 exists on December 31, 1999 is maintained in a restructured electric industry." 10 (PURA Sec. 39.101(£)). 11 Finally, PURA provides for a timely enforcement action and the exercise of 12 some "incentive regulation," in that PURA requires the PUCT to consider quality of 13 service when setting the rate of return. (PURA Sec. 36.052). 14 3. PURA/ECONOMIC FRAMEWORK: THE ALIGNMENT 15 STANDARD 16 17 Q. ARE YOU OFFERING AN ECONOMIC FRAMEWORK FOR ANALYSIS 18 THAT YOU DERIVE FROM PURA'S STATUTORY STANDARDS? 19 A. Yes, I am. There is a simple way to understand how service quality provided by 20 TDSPs can deteriorate relative to the integrated utility world of December 1999. 21 Q. PLEASE EXPLAIN. 22 A. In the integrated utility/captive customer model, "the market" consisted of captive 23 customers, and captive customers or their representatives accessed the regulatory 24 process to provide effective feedback on utility operations. This regulatory model 25 encouraged the private incentives of utility management concerning quality of service DIRECT TESTIMONY 16 GOODFRIEND 1 to be, depending on specifics of management and regulation, more or less aligned 2 with the interests of end-use customers (or at least aligned with regulatory perceptions 3 of end-user requirements). 4 Q. HOW SO? 5 A. Regulation could create incentives for the utility to align its expenditure pattern with 6 customer service requirements. In rate proceedings, regulators set prices and imposed 7 service standards. This kind of regulation provided readily available ways for end- 8 use customers or their representatives to access the regulatory process and express 9 dissatisfaction with rates, services, service offerings (rate design) and service quality. IO Considering the total dollars at risk in generation, transmission and distribution 11 combined, utility efforts to respond to customers and manage customer relations were 12 a necessary asset-preservation investment strategy. Absent effective regulation, there 13 was no need to consider regulatory feedback effects on its balance sheet when making 14 cost/quality decisions. 15 Q. HOW HAVE THINGS CHANGED? 16 A. A new problem introduced by Customer Choice is one of "incentive alignment" for 17 the remaining regulated utility, the TDSP. One of the purposes of regulation is to 18 create incentives for a utility to "internalize" important externalities, in other words, 19 to create incentives for the utility to take into account the effects of its decisions and 20 actions on costs borne by others when this "internalization" is in the public interest. DIRECT TESTIMONY 17 GOODFRIEND 1 Q. ARE YOU SAYING THAT AEP ISN'T PROVIDING TCC WITH ENOUGH 2 RESOURCES DEDICATED TO RETAIL CUSTOMER SERVICE QUALITY? 3 A. Yes, and I am saying more. Although a misallocation of resources is a part of the 4 answer, it is not the full answer. 5 Q. PLEASE EXPLAIN. 6 A. One can explain the poor quality of customer service at TCC as a consequence of 7 cost-cutting by AEP management in response to financial pressures (such as those 8 created by recent failed investments in unregulated businesses).6 To manage needed 9 cash flow, AEP allows the service quality offered by the regulated business to 10 deteriorate in order to compensate for cash flow lost by unregulated operations. This 11 describes a situation of unacceptable and impermissible cross-subsidy of the 12 unregulated operations by misallocation ofresources from the regulated business. 13 Although the evidence is consistent with this view, I believe this unacceptable 14 cross-subsidy is a symptom as well as a contributing factor to problems with 15 customer service at TCC. Said differently, even if AEP were not cross-subsidizing 16 losses, due to the incentive alignment problem I describe, we would still find TCC's 17 service quality to deteriorate with the arrival ofretail choice in ERCOT. 18 Q. WHY AREN'T AEP-TCC'S INCENTIVES TO PROVIDE QUALITY 19 SERVICE PROPERLY ALIGNED NOW? 20 A. Incentives have changed because the odds have changed. Especially in the case of 21 AEP, significant assets are no longer at risk in this regulatory proceeding. AEP has 6 See for example, the $5.8 million in trading losses that appears against Miscellaneous Income in TCC's Rate Filing Package, WP II-E-5. See also AEP's Annual Report for 2002. DIRECT TESTIMONY 18 GOODFRIEND 1 sold or will sell ERCOT assets upstream and downstream of its TDSPs. Unlike the 2 other TDSPs in ERCOT, AEP no longer has significant investment in affiliated REP 3 operations whose service quality depends, at least in part, on the service quality it 4 receives from the TDSP. Moreover, AEP is prohibited under its agreement with 5 Centrica from entering the ERCOT market as a residential and small commercial REP 6 until 2006.7 7 From a utility management perspective, generation is no longer subject to 8 rate-of-return regulation by Texas regulators. In ERCOT, the individual utility 9 transmission investment decision is now subjected to an ERCOT-wide priority 10 planning process and then annual costs are socialized. In subjecting major 11 transmission projects to ERCOT staff and stakeholder review, the ERCOT planning 12 process tends to operate like a pre-investment prudence review, reducing 13 disallowance risks (except perhaps for cost overruns) for larger transmission 14 investments. Thus, compared to the old world, the dollars at risk or exposure from 15 poor service quality are significantly reduced. End-use customers' dissatisfaction 16 with service from the distribution utility no longer poses the potential threat to 17 revenues or profits that it once did. 18 From an end-user perspective, finding the responsible party has become more 19 difficult and once found, the payoffs for effort are simply lower. With socialized 20 transmission costs, end-use customers of the TDSP are no longer directly responsible 21 for paying the costs of their TDSP's transmission investments. Thus, the payoff to 7 Notice and Request for Approval of Changes in Ownership and Affiliation of Mutual Energy CPL, LP and Mutual Energy WTU, LP, May 22,2002 Docket No. 25957, Attachments. DIRECT TESTIMONY 19 GOODFRIEND 1 end-use customers in terms of cost/bill reductions from using the regulatory process 2 to address concerns with service quality has declined. 3 Moreover, the complexity and interdependence of market transactions 4 necessary in order to provide end-user services has increased, requiring the 5 coordinated efforts of TDSPs, ERCOT and REPs. Not surprisingly, Customer Choice 6 engendered unprecedented levels of electricity customer complaints. 8 If customers 7 are unsure where responsibility lies, this complexity further reduces the pay-off to 8 end use customers or their representatives of holding a TDSP accountable for its 9 contribution (or lack thereof) in setting the level of service quality the market is 10 capable of providing. 11 Q. WHAT KIND OF STANDARDS HAS THE COMMISSION SET FOR TDSPS, 12 ERCOT AND REPS ? 13 A. The Commission has set quantitative standards for certain electronic transactions and 14 numerical and qualitative standards throughout its Customer Protection Rules. 15 Q. WHY HAS THE COMMISSION SET QUANTITATIVE STANDARDS FOR 16 CERTAIN ELECTRONIC TRANSACTIONS? 17 A. Essentially, the Commission has set quantitative standards for certain electronic 18 transactions in order to create accountability among parties for the success of highly 19 interdependent transactions. 8 See Report to the 78th Texas Legislature, Scope of Competition in Electric Markets in Texas, Public Utility Commission of Texas, January 2003, page 106 DIRECT TESTIMONY 20 GOODFRIEND Q. PLEASE EXPLAIN. 2 A. ERCOT is the central registration agent for retail premises and the electronic hub for 3 all retail electronic "enrollment" transactions. Electronic transactions are necessary 4 for customers to change REPs, change premises, receive electric service, etc. At the 5 beginning of the market, technical problems were affecting the ability of parties to 6 timely "turnaround" the necessary transactions. 7 Q. WHAT KIND OF STANDARDS APPLY TO TDSPS? 8 A. Standards are established for certain transactions by ERCOT Protocols. Some 9 standards also appear in TDSP tariffs. For example, when ERCOT sends a TDSP a 10 notice of a switch request, the ERCOT Protocol requires the TDSP to send an 11 electronic acknowledgement of the request back to ERCOT within two business days 12 of receipt. TDSPs are also required to send their invoicing out to REPs within tariff- 13 established time frames. 14 Q. WHAT ARE THE QUARTERLY PERFORMANCE REPORTS? 15 A. Among other things, Quarterly Performance Reports provide technical information 16 about several electronic transactions. To identify how successful ERCOT, TDSPs 17 and REPs are in moving electronic transactions over their interconnected networks 18 and in completing the necessary electronic lifecycles in a timely and accurate fashion, 19 the technical report examines some of the 47 standard electronic transactions in the 20 Texas market (Texas SET) that can occur. 9 9 Developed in response to early problems in turning around electronic transactions, the Performance Measure Reports require that ERCOT report transaction volumes and "success rates" in completing electronic transactions within established Protocols. The Commission established a benchmark for success rates equal to 98%. In other words, ERCOT, the TDSPs and REPs should strive to complete the electronic transactions that are their portion of the turnarounds within Protocol, 98% of the time. DIRECT TESTIMONY 21 GOODFRIEND 1 Q. DO THE QUARTERLY PERFORMANCE REPORTS PROVIDE OTHER 2 TECHNICAL INFORMATION? 3 A. Yes. Due to early market problems, a shadow system of "workarounds" or "safety 4 net" transactions came into being bypassing ERCOT and requiring the direct 5 coordination of TDSPs and REPs. The Quarterly Report requires some limited 6 reporting by TDSPs and REPs on these manual/electronic transactions and on inter- 7 company invoicing. I will be referencing some of this data later in my testimony. 8 Q. WHAT OTHER STANDARDS WILL YOU BE REFERENCING? 9 A. The PUCT has promulgated specific standards within its Consumer Protection rules. 10 A reading of these rules suggests that the qualitative standards I have suggested above 11 describe the essential elements that together can make or break service quality. IO 12 Q. HOW DO THESE FIVE DIMENSIONS OF SERVICE QUALITY RELATE 13 TO THE ALIGNMENT STANDARD FROM ECONOMIC THEORY? 14 A. Deficiencies in any one of these will impose unnecessary costs on the market. 15 Q. HOW DID YOU DECIDE TO PROCEED? 16 A. In order to investigate the quality of service provided to REPs, I decided to survey 17 REPs active in the TCC service area regarding service quality. 10 These are: (1) Quality and Timeliness of Communication, (2) Speed of Response, (3) Pro-active Problem solving, (4) Dedication of Resources and (5) Accuracy of Response. DIRECT TESTIMONY 22 GOODFRIEND 1 B. SURVEY DESCRIPTION AND RESULTS 2 1. INTRODUCTION AND ORGANIZATION 3 Q. HAS AEP-TCC SURVEYED REPS REGARDING THEIR EVALUATION OF 4 TCC SERVICE QUALITY? 5 A. No. 6 Q. HAVE OTHER AEP TDSPS IN STATES WITH RETAIL CHOICE 7 SURVEYED REPS REGARDING THEIR EVALUATION OF TDSP SERVICE 8 QUALITY? 9 A. No. There has been no survey. I I Moreover, there is no incentive structure in place at 10 AEP or TCC to reward employees according to REP perceptions of service quality.12 11 Q. HAVE ANY OTHER ERCOT TDSPS SURVEYED SERVICE QUALITY? 12 A. Within the last month, I understand that an anonymous telephone survey by a market 13 research firm is being conducted on behalf of CenterPoint, the TDSP in the Reliant 14 service territory. To my knowledge this is CenterPoint's first formal survey of its 15 REP customers. ERCOT also has announced plans for its first customer survey.13 16 Q. HOW DID YOU PROCEED? 17 A. To investigate TCC service quality, I created and sent a REP Customer Satisfaction 18 Survey to all REPs active in the TCC service territory. I surveyed four areas of 19 importance to REP service quality: (1) Responsiveness to REP inquiries, (2) 20 Educational programming and outreach to REPs, (3) Responsiveness in resolving 11 Response to Cities 2-97. 12 Response to Cities 2-96. 13 Ercot Report to RMS, 1/14/04. DIRECT TESTIMONY 23 GOODFRIEND 1 market problems generally, and (4) specifically, with respect to FasTrak issues. The 2 survey and cover letter is provided as Exhibit SJG-1. 3 Q. HOW IS THIS SECTION OF YOUR SERVICE QUALITY TESTIMONY 4 ORGANIZED? 5 A. First, I will introduce the survey. Second, I will report the numerical results of 6 responses on relative and absolute rankings of TCC. Third, I will review each of the 7 four topic areas for which I solicited comments. For ease of exposition, I will not be 8 discussing all the survey responses. However, I have included them all in matrix 9 form within the body of my testimony. I will be discussing some representative 10 responses that appear in the matrix. 11 Q. DID YOU EVALUATE THE RESPONSES YOU RECEIVED? 12 A. Yes. Research and discovery pennitted me to directly evaluate some of the REP 13 responses to the Customer Satisfaction Survey. I have supplemented the REP 14 responses with additional examples or illustrations related to assessing unnecessary 15 costs imposed on the market by TCC's service quality failures. 16 Q. WHY WAS THERE A NEED FOR AN ANONYMOUS SURVEY? 17 A. Because of the day-to-day working relationship with TCC, and fear of possible 18 retaliation, REPs suggested the need for anonymous survey response. Even so, 19 several REPs I contacted indicated that they would not be responding due to 20 confidentiality concerns. 21 Q. DO YOU BELIEVE FEAR OF RETALIATION IS RATIONAL? 22 A. Yes. REPs depend upon the cooperation of TDSP personnel. It is rational to fear 23 forms of retaliation such as assigning a new employee to work an critical issue for a DIRECT TESTIMONY 24 GOODFRIEND 1 particular REP, working orders from one REP before another, responding to emails or 2 phone calls more promptly, etc. that discriminate but are difficult to detect. 3 Q. ARE THERE SOME OTHER REPS YOU DID NOT EXPECT TO 4 PARTICIPATE? 5 A. Yes, based on economic self-interest it seemed less likely that I would receive 6 responses from REPs affiliated with AEP or REPs affiliated with other TDSPs. 7 Q. HOW LARGE THEN WAS YOUR POTENTIAL POOL OF RESPONDENTS? 8 A. These considerations leave 26 or 27 REPs as potential respondents. Roughly 113 of 9 these potential respondents completed and returned the survey. The respondent group 10 of REPs included those who had been in the market from the beginning and those 11 entered later; REPs serving Residential, Commercial and Industrial customers (or 12 some combination thereof), and REPs with different market shares and distributions 13 of overall market share in AEP. 14 2. NUMERICAL RESULTS 15 Q. YOU SAID EARLIER THAT YOU WOULD BE PROVIDING DIRECT 16 QUOTES FROM THE SURVEY IN ITALICS AS REPRESENTATIVE OF 17 YOUR FINDINGS FOR EACH AREA. DO YOU HAVE A 18 REPRESENTATIVE RESPONSE FOR THIS SECTION? 19 A. Yes. It all comes down to communication and responsiveness. Resource constraints 20 may play a role but CenterPoint and Oncor find themselves well in front of AEP and 21 TNMP. The relative ranking of AEP-TCC is consistent with the individual 22 respondent's statement . DIRECT TESTIMONY 25 GOODFRIEND 1 Q. HOW DID YOU PROCEED IN THIS AREA? 2 A. For each of the four survey areas (responsiveness to inquiries, education and 3 outreach, resolving market problems and FasTrak), I requested that respondents 4 provide a relative ranking of the four ERCOT TDSPs, from 1 (best) to 4 (worst). For 5 the four survey areas combined, respondents provided 30 relative rankings for AEP- 6 TCC. 7 The distribution of these ranks is represented by the following chart. 8 Figure 1: Relative Rank of TCC Among ERCOT TDSPs 8 .-~---========;-------------------, •Inquiries 7 7 (I) 7- Resolve Fas Trak ,_____ _ ____ 1!111 "'0s:: 6 - ~Educ & Outreach c. D Resolve Problems "' ~ 5 'O 4 ~ 3 s:: (I) ::s C" 2 ~ 1 u. 1 0 0 0 O+---==---~ Best 2nd 3rd Worst 9 10 Q. PLEASE DESCRIBE THE CHART. 11 A. The relative rankings are clustered at number 3, with a few outliers. The chart may 12 be read as indicating that for the Inquiries responses, indicated by solid black, 7 13 respondents gave TCC a 3rd, while 1 respondent gave AEP a 2nd and the other gave 14 AEP a 4th or Worst. For Education and Outreach, indicated by the diagonal stripe, 7 DIRECT TESTIMONY 26 GOODFRIEND 1 respondents gave AEP a 3rd and 1 respondent gave TCC a 4th. That one respondent 2 did not rank TCC on the question is indicated by a "0." (The "O"s indicate non- 3 responses ). While AEP does best on FasTrak, notice that there were only 6 responses 4 indicated by the hatch marks of 4 giving AEP a 3rd, 1 giving TCC a 2nd and 1 giving 5 TCC a 1. Some respondents indicated that they had not initiated FasTrak issues with 6 TCC. Others indicated they had little experience with TCC in this area. TCC fairs 7 worst on resolving market problems. While it is tempting to discuss the outliers, it 8 would be a mistake to give them too much attention, since some variation in opinion 9 is to be expected and the sample is small. 10 Q. DID YOU ALSO PROVIDE RESPONDENTS AN OPPORTUNITY TO 11 GRADETCC? 12 A. Yes. For each survey area, I requested that respondents provide a grade with 13 A=excellent, B::=good, C=fair, D=poor, and F=fail. The resulting frequency 14 distribution shows more variation in this small sample than the one above. This 15 results express differences in the graders' standards as well as differences of opinion. 16 Q. DO YOU HA VE A REPRESENTATIVE RESPONSE FOR THIS RANKING? 17 A. Yes. Management needs to make customer service a priority. 18 Q. DO REP RESPONSES SHOW A DIVERSITY IN STANDARDS? 19 A. Yes. Those REPs that want to use service quality as a competitive distinction will be 20 sensitive to TDSP service quality, since their ability to distinguish themselves 21 depends upon the TDSP's service quality. REPs competing on the basis of price are 22 less sensitive to service quality issues (as long as other REPs are getting the same DIRECT TESTIMONY 27 GOODFRIEND 1 level of service quality that they do). The distribution of REP grades is provided in 2 the following chart: 3 4 Figure 2: TCC Grade Distribution from REP Survey •Inquiries &'1 Educ & Outreach 1111 Resolve Problems D Resolve Fas Trak ~ 10 ~ (,!) >- ..c 8 3l"' 6 c: &. ~ 4 0:: 0 2 =t:I: 0 __.___ _ _ __ A Excellent BGood C Fair D Poor F Fail Grades for Performance 5 Q. WHAT IS TCC'S GRADE POINT AVERAGE? 6 A. Using 4.0 for A, 1.0 for D and 0 for F, TCC's overall grade point is 1.834. 7 Q. WHAT ARE YOUR COMMENTS ON THIS CHART? 8 A. Although the numerical results are interesting, they lack the consistency that appears 9 across the repeated written responses. The frequency distributions that result visually 10 from the ranking exercises provide information about where most responses lie 11 (central tendency) but also report some inconsistencies that exist in the responses. 12 The qualitative responses are much more uniform. DIRECT TESTIMONY 28 GOODFRIEND 1 Q. HOW IS THE PUCT STANDARD THAT YOU RECOMMEND RELATED TO 2 THESE REP STANDARDS? 3 A. The PUCT standard is more stringent because the PUCT has the responsibility of 4 evaluating service quality in light of all market costs, costs to REPs, to the market, to 5 the competitive process and to end-users. 6 Q. IF YOU WERE GRADING TCC, WHAT GRADE WOULD YOU GIVE TCC? 7 A. Applying the standard I urge the Commission to adopt, and based on the evidence I 8 will present, I would give TCC a grade of unacceptable, a Dor an F. 9 3. QUALITATIVE RESULTS 10 Q. HOW WILL YOU PROCEED IN THIS SECTION? 11 A. This section is divided into four subsections for each of the four survey areas. The 12 survey asked REPs for comment on TCC practice, and on best practices, whether 13 AEP-TCC could achieve best practice and, if so, how. For each survey area, I created 14 tables to catalogue all the narrative responses I received. There are three table rows. 15 The rows are: (1) TCC Practice, (2) Best Practice Standards/Suggestions for 16 Improvement and (3) Issue Subject to Further Analysis and/or Testimony 17 Recommendations for this area. Comments are further classified by the columns of 18 the table. Table columns identify the dimension of service quality to which the 19 comment most pertains. These service quality dimensions, which have been 20 discussed above, are: Quality and Timeliness of Communication, Speed of Response, 21 Pro-Active Problem Solving, Dedication of Resources, and Accuracy of Response. DIRECT TESTIMONY 29 GOODFRIEND 1 LACK OF RESPONSIVENESS TO REP INQUIRIES 2 Q. WHAT ARE YOUR GENERAL FINDINGS IN THIS AREA? 3 A. REPs found TCC slow to respond to inquiries and poor at maintaining 4 communication. They had many suggestions for improvement. A representative 5 statement of response is the following: At the REP relations level we are rarely able 6 to reach TCC representatives via telephone. Issue resolution usually takes between 7 2-4 weeks when we are able to reach a representative via phone. Issue resolution, 8 when communicated via email, usually takes 4-6 weeks. We attribute many of these 9 problems to lack of resources. We have one contact who handles all issues, from ES! 10 ID questions to tariff questions. This contact is the only contact for many other 11 REPs. 12 In contrast, REPs report that other TDSPs had a habit of maintaining 13 communication regardless of whether there was an outstanding issue or not. Other 14 TDSPs routinely send back data within 2 days without follow up contact. The 15 following table summarizes results. DIRECT TESTIMONY 30 GOODFRIEND 1 Dimensions of Service Quality Figure 3 Quality and Speed of Pro- Dedication Accuracy Responsiveness Timeliness of Response active of of to REP Inquiries Communication Problem Resources Response Solving At the REP relations level we rec is slow in TCC has relatively TCC Practice are rarely able to reach TCC responding to limited account representatives via historical usage management telephone. Issue resolution requests. For resources available usually takes between 2-4 example, in a to REPs to handle weeks when we are able to [redacted] letter of inquiries outside the reach a representative via authorization was scope of day to day phone. Issue resolution, when sent to TCC with operational issues. communicated via email, multiple ESI IDs. Responses to usually takes 4-6 weeks. We TCC was contacted business practices attribute many of these [redacted] times and policies, tariffs, problems to lack of and has not etc. are often resources. We have one responded. Often delayed if one or contact who handles all have to follow up on more contacts are issues, from ESI ID questions usage requests and unavailable. to tariff questions. This resend LOAs contact is the only contact for multiple times to get From our many other REPs. usage data back experiences, the poor We do not have a responsiveness is lot of ESl-IDs in the not due to AEP territory so we performance, but do not need a lot of due to resource help. However, constraints on the when we have Customer Relations needed responses Rep. to issues timing has been slow. Improvement in the supplying of historical data when requested with an LOA is needed. 2 DIRECT TESTIMONY 31 GOODFRIEND 1 Dimensions of Service Quality Figure 3 (cont.): Quality and Speed of Pro- Dedication Accuracy Responsiveness Timeliness of Response active of of to REP Inquiries Communication Problem Resources Response Solving Other TDSPs were and are in We generally Need: Annual Need: a designated Best Practice constant contact with our receive responses meetings to point of contact -- Standards/ REP, not just in cases of from other TDSPs "get to know" name and personal problem or transaction in 2 days. the company email. Someone to Suggestions for resolution. and individual develop a working Improvement Other TDSPs: REP relations relationship with. Other Customer Relations Routinely send managers. Also, [need] Reps make it a point to back data within 2 knowledgeable communicate on a weekly or days without follow OtherTDSPs support Reps who biweekly basis to ensure up contact. have: have escalation customer care. Redundancy of support if they need Other TDSPs: Very transaction it. Go out and meet the REPs fast response to procedures they represent and make ii a requests. (i.e., policy to answer all emails. workarounds Need: Quicken through email, response times to fax and requests for telephone) historical information. (2 REPs) 2 3 NO EDUCATIONAL PROGRAMMING AND OUTREACH TO REPS 4 5 Q. WHAT WERE YOUR FINDINGS? 6 A. The strong consensus of opinion in the numerical rankings on this aspect of TCC 7 service is confirmed in what REPs had to say on this issue. Four respondents were 8 unaware of any educational or outreach program. Another commented that TCC has 9 never hosted any informational workshops for REPs. This respondent continued: No 10 proactive measures have been taken to inform REPs of TCC's business practices 11 regarding customer enrollment, billing, service order processing or issue resolution. 12 When attempting to obtain answers to these types of day to day operational questions 13 answers are at times inconsistent and the appropriate personnel are difficult to 14 contact. DIRECT TESTIMONY 32 GOODFRIEND Q. WHAT UNNECESSARY SERVICE COSTS ARE CREATED BY THIS 2 FAILURE TO COMMUNICATE? 3 A. Labor costs associated with manual interventions and reparative software costs. The 4 REP responded: TCC provides very little outreach to help educate REPs. For 5 example, TCC altered the format of usage data responses. We had no advance notice 6 of the change. Our systems are configured to automatically upload usage data. The 7 change in format did not work with our systems. This caused operational problems 8 until we recognized the change and were able to alter our systems. This REP 9 contrasted TCC with Oncor, reporting that Oncor also altered its format for usage 10 data responses but provided ample advance notice and an example of the new format. 11 This advance notice permitted system changes and the avoidance of operational 12 problems. 13 Q. WHAT IS YOUR OBSERVATION ABOUT THESE COMMENTS? 14 A. TCC's poor ranking on education and outreach show a lack of interest not a lack of 15 resources. This is not a situation where TCC must incur significant costs to support 16 market development. This is simply a lack of pro-active customer focus. For 17 example, a comment was: Holding workshops and proactive communication are 18 attainable goals for AEP; There is no clear reason why TCC should not be able to 19 host such workshops for REPs. This should not only improve the operating efficiency 20 of REPs but that of TCC as well. DIRECT TESTIMONY 33 GOODFRIEND 1 Q. HAVE YOU PROVIDED SPECIFIC RECOMMENDATIONS RESULTING 2 FROM YOUR ANALYSIS OF THIS CUSTOMER SERVICE ISSUE? 3 A. Yes. These recommendations are included in summary at the beginning of my 4 testimony. 5 6 Dimensions of Service Quality Figure 4: Educational Quality and Pro-active Dedication of Programming Timeliness of Problem Solving Resources and Outreach Communication To date, TCC has never hosted Three REPs: To respondent's any informational workshops for TCC Practice knowledge, no education or REPs. No pro-active measures outreach provided. have been taken to inform REPs of TCC's business We are not aware of any practices regarding customer educational programs offered by enrollment, billing, service order TCC. However, we have processing or issue resolution. received email When attempting to obtain updates/correspondence answers to these types of day regarding TCC processes. to day operational questions answers are at times inconsistent and the appropriate personnel are difficult to contact. TCC provides very little outreach to help educate REPs. For example, TCC altered the format of usage data responses. We had no advance notice of the change. Our systems are configured to automatically upload usage data. The change in format did not work with our systems. This caused operational problems until we recognized the change and were able to alter our systems. DIRECT TESTIMONY 34 GOODFRIEND Dimensions of Service Quality Figure 4: Educational Quality and Pro-active Dedication of Programming Timeliness of Problem Solving Resources and Outreach Communication Three REPs: Oncor and Invited to office and provided Best Practice CenterPoint have regular Detailed Billing Analysis Standards/ workshops designed to educate notebook of all accounts. Other TDSPs offer periodic REP. This is helpful because it Breakout and definition of each training &seminars. Also, Suggestions for keeps REPs up to date on type and explained how to have one specific rep relation Improvement changes with the TDSPs and interpret the bill. person assigned also allows us interaction with our CSRs in person. We never Other TDSP's meetings Other TDSPs: (Two Reps had a physical meeting with provide: gaining a better commented) Meetings provide main contact at TCC. understanding of internal TDSP opportunity to meet processes, an opportunity to representatives face to face. CenterPoint holds meetings as address specific issues or necessary to discuss procedural concerns and an opportunity to or market changes that REPs meet and greet. We would like need to know. to see TCC offer these programs as well. They(Oncor] also cover any upcoming tarriff (sic] changes and cover updates to their web site. CenterPoint holds meetings as necessary to discuss procedural or market changes that REPs need to know. (Two REPs) 1 2 INACCURACIES AND UNRESPONSIVENESS WORSEN MARKET PROBLEMS 3 Q. WHAT IS THE NEXT AREA OF EVALUATION? 4 A. The next area is how well TCC responds in resolving market problems. This subject 5 area elicited the longest and most numerous responses. Before presenting the 6 tabulated responses, I want to present the results of my investigation of a general, but 7 repeated allegation. DIRECT TESTIMONY 35 GOODFRIEND 1 Q. WHAT WAS THE REPEATED REP ALLEGATION YOU INVESTIGATED? 2 A. A REP respondent stated: rec is also usually the first group to complain about a 3 change in the market and the last to get their software updated. rec often appears 4 to want to do just what is required and nothing more. Another REP made the same 5 point more diplomatically, stating: AEP is generally somewhat inflexible in changing 6 their internal practices to accommodate market concerns. 7 Q. IS THIS ALLEGATION OF PARTICULAR INTEREST IN YOUR 8 FRAMEWORK? 9 A. Yes. These allegations are another way of identifying the alignment problem. In 10 failing to accommodate market concerns, these REP statements imply that TCC is 11 imposing costs on the market that directly diminish the quality of service delivered to 12 ERCOT retail market participants. 13 Q. WERE YOU ABLE TO FIND SOME EVIDENCE SUPPORTING THIS 14 ALLEGATION? 15 A. Yes. But before reviewing it, having a bit more background about electronic 16 transactions in ERCOT is helpful. 17 Q. WILL YOU BE DESCRIBING THE REASON FOR MOVING FROM THE 18 CURRENT VERSION OF TEXAS SET, VERSION 1.6 TO A NEW SERIES 19 RELEASE, TEXAS SET 2.0? 20 A. Yes. At the present time, service orders, such as requests for switching a customer's 21 REP, moving a customer either in or out of an existing premise, providing 22 connection, reconnection or disconnection, requests for changing when a meter is 23 read or for current or historical usage data, etc. all arrive to the TDSPs in DIRECT TESTIMONY 36 GOODFRIEND 1 chronological time. When orders arrive in chronological time but out-of-sequence for 2 the implied cycle of transactions on a single active premise location (ESI ID), rejects 3 occur. 47% ofrejects are caused by this type of problem.14 4 In these cases, the TDSPs and REPs must manually intervene and workaround 5 the reject. These manual workarounds in tum give rise to other problems. Texas Set 6 2.0 will solve the problem of multiple non-sequential transactions on a single ESI ID 7 via a "parking lot" or stacking solution. Over the last few months, ERCOT 8 information technology and customer service employees have been offering training 9 seminars to acquaint market participants with these changes. The ERCOT Protocols 10 contain gray-tone provisional sections incorporating new Protocol standards once 11 Texas SET 2.0 is in place. 12 The seminars are necessary because Texas SET is literally the standard for 13 how electronic data transactions between market participants must interface, so it is 14 mandatory that each market participants be able to fully execute Texas SET. 15 Everyone who participates in the market must update their systems with changes in 16 Texas SET. Substantial market benefits are anticipated from this major upgrade. IS 17 Finally, in the document below references to MACSS is to a customer 18 information system internal to the AEP system. References to the "parking lot" are 19 references to ERCOT's problem resolution embodied in the release of Texas Set 2.0. 14 ERCOT, Solution to Stacking Educational Seminar, 12/9/03 available from RMS (Keydoc's) section at www.ercot.com. IS ERCOT, Solution to Stacking Educational Seminar, 12/9/03 lists expected benefits as: significant reductions in rejects, significant reduction in the need for Safety Net Move-ins, better manages customer expectations regarding dates, billing, etc, fewer backdated clean up efforts, fewer cancel/rebills, helps keep systems in synch, reduces unaccounted for energy, reduces transaction volume, expedites connecting and billing the customers by the correct REP and improves transactions reliability. DIRECT TESTIMONY 37 GOODFRIEND 1 Q. WHAT IS THE DOCUMENT YOU ARE PROVIDING BELOW? 2 A. Reproduced below is a Customer Choice Operations Business Case Analysis 3 provided by TCC in discovery. This document rather perfectly illustrates my thesis: 4 absent Commission action in this case, TCC will disregard significant market costs it 5 imposes on others by its actions. Narrow profitability concerns are driving TCC 6 service quality decisions. TCC has actively resisted improvements benefiting the 7 market. The evidence corroborates the REP survey allegations I have quoted above. 8 Q. WHY DO YOU INCLUDE THE ENTIRE BUSINESS CASE ANALYSIS? 9 A. The document itself is important and the complete context of the document is an 10 important reference. The business case analysis does a good job of describing the 11 significant costs being imposed on the market by delaying the implementation of 12 Texas Set 2.0. Then, when discussing alternatives to the necessary investment the 13 analyst says: The parking lot will benefit the overall functioning of the market and will 14 benefit CRs [competitive retailers or REPs]. Due to the minimal benefit to AEP TDSP, we 15 have attempted to delay implementation through negotiation in working groups. 16 The author's use of the past tense is disturbing. 17 DIRECT TESTIMONY 38 GOODFRIEND Source: Cities 10 Q 12 FIGURE 5: BUSINESS CASE, CUSTOMER CHOICE OPERATIONS Business Case Business Unit: Customer Choice Operations Project Name: CCPRIL TX Service Order Parking Lot (Texas SET 2.0) Project ID: CHG000000724085 Start Date: End Date: Executive Summary: AEP is required to conform to the ERCOT Protocols as specified in Texas Standard Electronic Transactions (SET.) Texas SET will make periodic releases to address market issues and it is mandatory that AEP make all changes necessary to comply. Consistent with the planned release of TX SET 2.0, AEP will need a new application for Texas to properly sequence multiple future-dated service orders for a single premise. The BU and IT sponsors are Jim Sorrels and Bill Vogel, respectively. Current Situation and Problem Statement: Today, transactions are received in the order they are sent from market participants, not necessarily in chronological order. Service orders entered into MACSS that are not in chronological sequence cannot be completed. These out-ofsequence orders either must be manually processed or rejected back to the CRs for resequencing. Either of these options requires significant manual effort to resolve. Each TDU in Texas has this same problem and the market has decided that the appropriate solution is for each TDU to modify their systems to deal with out-ofsequence transactions. Project Description: Functionality will be established to ensure that as the transactions are received by MACSS, they will be "parked", or held, until just before the event when the specific transaction is needed (to provide time for other orders to arrive). The transactions will then be properly sequenced to the work management system and allowing each to complete appropriately, instead of being exceptioned for manual processing or being rejected back to the CRs. Solution Overview: Implementation would allow AEP to comply with TX SET and reduce the workload associated with.fixing problems resulting from out-ofsequence transactions. Solution Detail: MACSS has estimated a delivery cost of $106,080. There is lost opportunity costs in that other projects that have revenue benefit will be delayed. An unquantified, but tangible benefit would be the reduction in manual processing necessary to fix out-of sequence transactions. The risk of not implementing these changes is that we would be in non-compliance with TX SET, with potential regulatory repercussions. Alternatives Considered: Tlte parking lot will benefit the overall functioning of the market and will benefit CRs. Due to the minimal benefit to AEP TDSP, we have attempted to delay implementation through negotiation in working groups. Implementation Summary: The anticipated delivery date for this market requirement is May 2004, subject to formal approval of a schedule by ERCOT. Relationship to other Initiatives: This project is consistent with other system modifications and enhancements required in the TX marketplace. Metrics: Success will be measured by the successful implementation of Texas SET 2.0 and our associated internal transaction processing. The benefits should be seen in the marketplace immediately. DIRECT TESTIMONY 39 GOODFRIEND 1 Q. HOW HAVE REPS CHARACTERIZED OTHER WIRES COMPANIES' 2 PARTICIPATION IN WORKING GROUPS? 3 A. In describing best practices among other wires companies, one REP said: Other 4 Wires Companies have got a lot of active members involved in many market 5 committees and subcommittees. These members are taking the time to improve the 6 market place through new software, faster hardware, better logic, improved 7 communication between REPs and more accurate market reporting. They are 8 proactively seeking solutions to lingering problems and trying to clear out all of the 9 old ones. 10 Q. BEFORE YOU LEAVE THIS TOPIC, IS THERE OTHER EVIDENCE 11 PERTINENT TO TCC'S SUPPORT OF MARKET WIDE SERVICE 12 IMPROVEMENTS AND COST REDUCTION EFFORTS? 13 A. Yes. TCC lags significantly behind Oncor and CenterPoint in providing the resource 14 investment needed for Texas SET 2.0. Oncor is 95% through the design stage and 15 90% through the build stage for Texas SET 2.0. CenterPoint is 85% through the 16 design stage and 25% through build. In contrast, AEP is 20% into the design stage 17 with no build and TNMP is 10% in the design stage with no build, according to recent 18 self-reports. l 6 19 Q. IS THERE ANOTHER CHARACTERIZATION OF TCC THAT IS ALSO 20 CAUSE FOR CONCERN? 21 A. Yes. AEP has a history of taking unilateral action against Market Rules e.g., billing 22 customers for T&D charges who showed no REP of Record. 16 The complete ERCOT presentation is provided in Workpapers. DIRECT TESTIMONY 40 GOODFRIEND 1 Q. WERE YOU ABLE TO INVESTIGATE THIS ALLEGATION? 2 A. Not definitively. It's clear that TCC spoke with Commission staff concerning 3 unbilled customers. In the early stages of the market there were customers for whom 4 either the TDSP and/or ERCOT had no "REP of record." TCC decided to direct bill 5 these customers without a REP of record and it appears that in the test year, this 6 brought in over $1.2 million to TCC.17 Whether TCC sent the letter first and 7 discussed it with Staff after the fact or visa versa, I do not know. I was also unable to 8 determine to what extent the Commission itself had an opportunity to comment on 9 TCC's action. 10 Q. WERE YOU ABLE TO INVESTIGATE THIS ALLEGATION OF 11 UNILATERAL ACTION USING OTHER INFORMATION? 12 A. Yes. I asked about whether TCC had ever discouraged a REP from using the FasTrak 13 process. TCC responded: In fewer than a dozen instances, TCC has asked certain 14 REPs not to utilize FasTrak for particular billing and payment issues. 15 In the discovery response quoted, TCC reasoned that it was burdensome for 16 TCC to use FasTrak and so substituted its own databases and archives to track the 17 disputes. TCC opined that FasTrak in its present form "is not necessarily the best to 18 tool to use in the instances discussed above." 18 19 Q. WHAT DO YOU MAKE OF THIS UNILATERAL ACTION? 20 A. The unilateral decision to bypass market processes can impose market costs. While it 21 may be burdensome at times for market participants to use FasTrak in cases where 17 TCC Workpaper 11-E-5 line 40 "CWRR" l 8 Response to Cities 15-3 DIRECT TESTIMONY 41 GOODFRIEND 1 multiple premises share a common transactional problem, FasTrak is the means by 2 which ERCOT, as the central registration agent, monitors and identifies transaction 3 problems, trends and prioritizes needs for improvement. Once logged, FasTrak issues 4 are never deleted. They become part of the knowledge base of historical information 5 for each active premise and can be searched by individual ESI-ID when needed to 6 provide background and/or resolve issues.19 Here, again TCC seems to show a basic 7 disregard for the effects of its decisions on the market as a whole. 8 Q. WILL YOU BE PRESENTING OTHER EVIDENCE THAT 9 CORROBORATES REP'S STATEMENTS OF CONCERN ABOUT TCC 10 PERFORMANCE? 11 A. Yes, but first I will review specific survey findings. Although I have tried to 12 categorize responses in this section by quality dimension, in fact, it seems that most 13 examples indicate a combination of factors are responsible for performance problems. 14 The first two examples focus on the role of inaccuracies as the source of later market 15 problems. In the instances described, inaccuracies impose direct costs on REPs and 16 end-use customers and may impose a second round of costs because of slow 17 responsiveness in resolving the initial inaccuracies: 18 The first example addresses errors in TCC's data at ERCOT: 19 TCC still has a lot of issues with inaccurate address/ESJ-ID information at 20 ERCOT. Many consumers in the TCC region are affected by un-authorized switches 21 due to incorrect information in the ERCOT portal and information TCC provides by 22 phone to the CR. 19 See Day to Day FasTrak Issues Users Manual 10/24/2003 -Version 4.0 available from www.ercot.com. DIRECT TESTIMONY 42 GOODFRIEND l The second example shows the effects of inaccurate use of a Texas SET 2 transaction sequence. This may also be evidence of a resource or training problem at 3 TCC. 4 There have been instances where a meter exchange had occurred and TCC 5 was sending 814_20 transactions [create/maintain/retire ESI-ID request} indicating 6 a meter removal. Then, TCC would send an 814_20 transaction indicating a meter 7 add. Once this Texas SET error was acknowledged by TCC it still took 4 months for 8 them to correct the problem. This incorrect use of the ESI-ID transaction caused 9 REPs additional workload, including REPs contacting the customer via telephone to 10 question the reason for the meter removal, the submission [of} final invoices to the 11 customer and the creation of new customer accounts. 12 Q. WHAT ABOUT BEST PRACTICE IN THESE AREAS? 13 A. With respect to speed and accuracy, REPs responded that other wires companies: 14 provide timely and accurate connections based on 814-04105 [switch notification and 15 enrollment] transactions and safety-net/priority connections; are in synch with 16 ERCOT relating to address and ESI-ID information; and respond to inquiries within 17 a 2-hour time frame. DIRECT TESTIMONY 43 GOODFRIEND Figure 6: Dimensions of Service Quality Responsiveness Quality and in Resolving Timeliness of Speed of Pro-active Problem Dedication Accuracy of Response Market Communication Response Solving of Resources Problems It all comes down to An isolated AEP is generally TCC is also TCC still has a lot of TCC Practice communication and example of poor somewhat inflexible usually the issues with inaccurate responsiveness. resolution of a in changing their first group to address/ESI-ID Resource constraints market issue internal practices to complain information at ERCOT. may play a role but occurred when accommodate market about a Many consumers in the CenterPoint and TCC issued concerns change in the TCC region are affected Oncor find market market and by Un-authorized themselves well in transactions with Responds well but the last to get switches due to incorrect front of AEP and inaccurate meter other TDSPs more their software information in the TNMP data. The issue helpful. updated. TCC ERCOT portal and was identified and often appears information TCC provides AEP has a history of brought to the We have repeatedly to want to do by phone to the CR. taking unilateral attention ofTCC requested a report just what is action against in [redacted]. from TCC regarding required and There have been instances Market Rules e.g., After multiple outstanding invoices nothing more. where a meter exchange billing customers for follow up phone and TCC has failed to had occurred and TCC T&D charges who calls and emails acknowledge or All are good was sending 814_20 showed no REP of the majority of respond to voicemail except for transactions Record. the impacted ESI or email TNMP. TCC [create/maintain/retire IDs with inquiries ... Then, after could ESI-ID request] indicating When issues arise inaccurate meter months of making probably a meter removal. Then, multiple emails must data were finally requests, TCC sent a improve TCC would send an be sent before corrected and the spreadsheet with ranking with 814 20 transaction answers provided. issue was [redacted] invoices more staff. indicating a meter add. resolved entirely indicating they were Once this Texas SET in [redacted]. past due. Of those, error was acknowledged During this [7 (redacted] were by TCC it still took 4 month period] never received months for them to time, no pro- [before] and were correct the problem. active measures over 60 days old; This incorrect use of were taken by [redacted] were the ESI-ID transaction TCC to identify duplicates; caused REPs additional and correct the [redacted) were workload, including REPs relevant ESI IDs rejected (redacted] ... contacting the customer affected during via telephone to question this period. the reason for the meter removal, the submission Unmetered [of] final invoices to the service resolution customer and the creation takes 4-6 weeks. of new customer accounts based on the new meter Meter re-reads information. and cancel re-bills are not timely. DIRECT TESTIMONY 44 GOODFRIEND Many other ..it was [only] TCC also does not TCC Practice TDSPs send back through our perform a connection on (cont'd) IDR and non-IDR employees research move-in on the dates they data much faster that these issues were confirm from the 814- than TCC. The discovered. TCC did 04105. (For example, if IDR data is not offer any the CR receives an 814- especially slow in resources or 04105 from TCC with a arriving to us. A assistance in connect date of 12.09.03, quicker evaluating the the service may not be turnaround would contents of the connected until 12.14.03 be most helpful. spreadsheet. or 12.15.03. Even though TCC has a safety Luckily I have not No ESI-IDs account net/priority connect had a lot of notation is made process, they never follow problems with when a CR calls in, through when a request is TCC in quite a so there is no history made. while. However, kept on any ES I/ID. when there is a problem the response is fairly slow. Best Practice Other Wires Other wires (TCC] management Best practice Standards/ Companies : have companies: needs to make is to follow Suggestions for got a lot of active provide timely customer service a through on Improvement members involved in and accurate priority. issues. Most many market connections based issues committees and on 814-04/05 CenterPoint and resolved subcommittees. transactions and Oncor both take what easily but These members are safety-net/priority they are given from those that are taking the time to connections; are the CR's and actively more difficult improve the market in synch with participate at WMS, following place through new ERCOT relating RMS, and Texas SET through are software, faster to address and to reach out and important to hardware, better ESI-ID assist the evolution of customer logic, improved information. the best in service. communication Respond to deregulated markets between REPs and inquiries within a in the U.S. today. CNP and more accurate 2 hour time Oncor have market reporting. frame. Yes, [best practice is the better They are proactively achievable by TCC]. capability for seeking solutions to TCC has the ability working lingering problems to improve capability around and trying to clear for working around market out all of the old market problems problems ones. through structured through procedures and structured AEP TCC can be contacts for procedures assured that if they resolution. and contacts are actively involved for resolution. and listen to their customers, ERCOT can only evolve into a better market than we have now. DIRECT TESTIMONY 45 GOODFRIEND 1 BILLING AND INVOICING: FOUNDATIONS FOR ERROR 2 3 Q. DID YOU INVESTIGATE ISSUES RELATING TO THE ACCURACY OF 4 BILLING AND INVOICING? 5 A. Yes. In this section I discuss TCC's use of estimates for meter reads and related 6 problems of billing and invoicing. Prompt and accurate billing and invoicing are 7 foundational issues because poor processes here can snowball into additional 8 problems. Any deficiencies in dedicated resources appear more severe when 9 underlying processes or systems are prone to error. Another REP provided a good 10 example of the relationship between data inaccuracy and slow response: 11 An isolated example of poor resolution of a market issue occurred when TCC 12 issued market transactions with inaccurate meter data. The issue was identified and 13 brought to the attention of TCC in [redacted]. After multiple follow up phone calls 14 and emails the majority of the impacted ES! IDs with inaccurate meter data were 15 finally corrected and the issue was resolved entirely in [redacted]. During this [7- 16 month period] time, no pro-active measures were taken by TCC to identify and 17 correct the relevant ES! IDs affected during this period. 18 Another REP noted: Meter re-reads and cancel re-bills are not timely. 19 Prompt and accurate billing and invoicing are foundational issues. Wires 20 charges include kW and kWh charges and invoices must be cancelled and re-billed 21 when underlying usage data is incorrect. In the ERCOT protocols, a meter read error 22 gives rise to four separate electronic transactions, a cancel and rebill of the associated 23 usage data and a cancel and re bill of the associated invoice. DIRECT TESTIMONY 46 GOODFRIEND 1 Moreover, timeliness and accuracy are both important service dimensions, but 2 they are not independent. Estimated meter reads can become a source of inaccuracy. 3 Inaccuracy can become a drag on responsiveness as the number of errors that have to 4 be corrected increase. In tum, the volume of cancel/rebills increases and rebillings 5 take longer to send out because the necessary corrective actions for usage information 6 strain existing resources. 7 Q. DOES THE COMMISSION SET STANDARDS FOR BILLING ACCURACY? 8 A. No, however, Subst. R.§ 25.25 provides limits to the use of estimated bills. When 9 questioned as to policy concerning the use of estimates versus actual meter reads, 10 TCC said that its policy concerning the use of estimated versus actual meter reads is 11 to comply with the rule.20 The rule says: An electric utility may submit estimated 12 bills for good cause provided that an actual meter reading is taken no less than every 13 third month. 14 Further, under existing consumer protection rules, REPs must notify 15 customers if the REP is unable to issue a bill based on an actual meter reading due to 16 TDSP or other failure to timely provide actual usage and inform the customer of the 17 reason for the issuance of an estimated bill.21 18 Q. HOW ACCURATE ARE TCC'S ESTIMATED METER READS? 19 A. The PUCT has no standards specifying particular methodologies for usage estimation. 20 TCC has provided documents describing the AEP estimation programs in use by TCC 21 since 1/112002. The estimation methods rely on simple extrapolations of historical 20 TCC Response to Cities 15-1. 21 See Subst. R. §25.479(e). DIRECT TESTIMONY 47 GOODFRIEND 1 meter reads or historical estimates. The estimates are not adjusted to recognize 2 differences in weather as a factor affecting usage. 22 3 Q. WHAT IS AEP'S VIEW? 4 A. AEP must agree with me that its estimation method needs improvement. In response 5 to a discovery request provided 2/4/04, AEP provided a business case started 6 12/04/03 titled Load Research Analysis Preliminary Plan for MACSS Bill estimation 7 improvement. The plan includes a more statistically sophisticated approach and a 8 weather-related adjustment for some customers. Expected completion date is May 9 2004.23 10 Q. ARE THERE OTHER POTENTIAL ACCURACY ISSUES ASSOCIATED 11 WITH TCC'S USE OF ESTIMATED METER READS? 12 A. Yes. TCC's current approach allows TCC to "dial up or dial down" its acceptable 13 level of accuracy. 14 TCC explains that in its approach to estimation, the acceptability of estimates 15 depends on the TCC's choice of an accuracy tolerance limit. If the tolerance limit is 16 loosened, more estimates are accepted as "good." When TCC is unable to create 17 estimates that are good enough, then the account is a "no bill" for the current reading 18 date with obvious cash flow implications for TCC.24 It is not surprising that one of 19 the measures TCC tracks for customer operations functions is the level of no bill 20 accounts more than 10 days old, and that there are very, very few of these.25 22 Response to Cities 15-2, Attachment 1. 23 Response to Cities 35-2, Attachment 1. 24 Response to Cities 16-6. 25 Response to Cities 30-14 attachment page 4 of 6. DIRECT TESTIMONY 48 GOODFRIEND 1 Q. WHAT HAPPENS IF TCC'S AUTOMATED SYSTEM TRIES TO ESTIMATE 2 A THIRD MONTH IN A ROW? 3 A. PUCT rule §25.25 requires an actual meter read every third month. TCC says: If the 4 automated system tries to estimate for a third month, then efforts are made to obtain 5 an actual reading. This may result in manual estimation. Because the automated 6 system will not estimate accounts with demand greater than 10 kW, all estimates for 7 these larger accounts are manual. Except for a small pilot program using remote 8 meter reading, all other meter readings require a premise visit.26 9 Q. WHAT HAS HAPPENED TO THE VOLUME OF TCC ESTIMATED METER 10 READS SINCE CUSTOMER CHOICE? 11 A. It has exploded in all rate classes. 12 Q. WHAT INCENTIVE ALIGNMENT PROBLEM DOES THIS SUGGEST? 13 A. Obviously, for every estimated meter read, a premise visit may be avoided. Provided 14 data indicates the cost-savings to TCC. Using TCC's fully embedded cost estimate to 15 a REP requesting a re-read or out-of-cycle read, the savings per avoided read would 16 be about $17.00. Eliminating supervisory overheads, and using just direct meter read 17 avoided costs saves $5.60 on the meter reader and $1.98 on the truck. 18 Q. WHAT DATA DO YOU HAVE TO SUPPORT YOUR STATEMENT THAT 19 THE VOLUME OF METER READS HAS EXPLODED IN ALL RATE 20 CLASSES? 21 A. TCC provided data on the percentage of estimated meter reads by customer class 22 since January 2000, well before Customer Choice began. The data series continues 26 Response to Cities 16-6. DIRECT TESTIMONY 49 GOODFRIEND 1 through November 2003.27 The graphic below visually demonstrates the change in 2 TCC's reliance on estimated meter reads, beginning roughly with the Pilot Program 3 for Choice. 4 As the graphic makes clear, there has been a dramatic increase in estimated 5 meter reads, beginning roughly at the time of the Pilot Project. As could be expected 6 from this visual view of the data, the observed differences in means before and after Figure 7: Meter Reading Accuracy Percent Estimated Meter Reads Integrated Utility vs Retail Choice • • Residential .... -commercial lndnstria! ' - - · Public Authority ' " --·-- Start of Retail Choice --+ .--- l --•----- - -- ' ' •' .. - -ti-ii--j-- ---- ----~-- \ - - -\_------ -- - '' -,--- ~ !- Start of Pilot Project _______.: : ·~ -~; _L :, I } 1~ i: ~ - __ :_v_ ~ ' • :•,lil.._"l ~ ' j_ ~_%_ 7 the onset of choice are statistically significant for each customer class.28 8 27 Response to Cities 15-1, Attachment 1. 28 So as not to influence the results, I have removed the month in which Hurricane Claudette led to use of estimated meter readings from the data provided. DIRECT TESTIMONY 50 GOODFRIEND 1 Q. HOW MANY ESTIMATED METER READS DO THE PERCENTAGES 2 DEPICTED REPRESENT? 3 A. In discovery, TCC reported a total of 594,632 automated estimated meter reads since 4 1/1/02 and 55,332 manual estimates since 111/02. Thus, since 1/1/02, TCC has relied 5 upon approximately 650,000 estimated meter reads in total.29 6 Q. HOW MANY ESTIMATED METER READS WERE THERE BEFORE 7 CUSTOMER CHOICE? 8 A. By my estimates, there would have been only about 100,000 or so estimated meter 9 reads (through November, 2003) ifTCC had continued its pre-Choice practices.30 10 Q. HOW MUCH HAS THE NUMBER OF ESTIMATED METER READS 11 INCREASED? 12 A. The number of estimated meter reads have increased by 550,000 over the 23 month 13 period since Choice began. This indicates that at current customer levels, some 14 100,000 estimated meter reads rather than the 650,000-meter reads would have 15 occurred by now had historical norms continued. 16 Q. HOW MUCH MONEY IS TCC SAYING THROUGH ITS CHANGED 17 PRACTICE? 18 A. Using $5 for net avoided cost for TCC, on an annual basis the increase saves TCC 19 about $1.4 million annually. The net avoided cost approach recognizes that there will 20 be cost impacts to TCC, for example in higher levels of cancel/rebill transactions. 29 Response to Cities 16-6. 30 The actual calculations are provided in Workpapers. Depending on assumptions the range of baseline or pre- Choice estimated meter reads runs from 83,000 to 180,000 and, correspondingly the range of increase runs from 567,000 to 470,000 expressed cumulatively. DIRECT TESTIMONY 51 GOODFRIEND For illustration, I am assuming a net savings of $5 from TCC's decision to increase 2 the use of estimated meter reads. 3 Q. WHAT ARE THE EFFECTS OF 550,000 ADDITIONAL ESTIMATED READS 4 ON END-USE CUSTOMERS, REPS AND THE MARKET? 5 A. The Company provided an analysis of AEP-wide data on this topic. The AEP 6 analysis suggests that approximately 50% of AEP's required billing adjustments each 7 year relate to bill estimation. For AEP, 27% of customer calls are related to high bill 8 concerns, including estimations. Over the period January through July 2003, 4.7% of 9 all AEP billing complaints were for inaccurate estimations.31 10 Q. CONSIDER END-USERS. WHAT COSTS ARE IMPOSED ON END-USERS? 11 A. First, depending on the contact option chosen, the end-use customer will need to call 12 the REP or possibly, TCC directly to inquire about the bill. The customer may feel 13 the need to escalate the inquiry into a complaint, engaging in the necessary phone 14 calls and other transactions. 15 Second, a surprised customer is not a happy customer. REPs have indicated 16 that they must respond to customers' bill shock associated with estimated reads, 17 particularly where a seasonal rate is employed. In this context, the REP must decide 18 whether a request for re-reads is in order, and, depending on the arrangements, either 19 the REP or the customer becomes subject to the Special Meter Reading Fee. 31 TCC Response to Cities 15-2, Attachment 1. DIRECT TESTIMONY 52 GOODFRIEND 1 Third, use of estimates followed by an ultimate true-up when the meter is read 2 makes it more difficult for customers to judge savings they receive from their chosen 3 REP. As a limiting case, the customer may feel the need to search for and switch to 4 another REP. 5 Q. WHAT COSTS ARE IMPOSED ON ERCOT MARKET PARTICIPANTS? 6 A. The relationship between estimated meter reads and the need for cancel and rebill 7 transactions suggests that TCC will have a higher level of cancel and rebill 8 transactions than otherwise. Since four transactions accompany every cancel with 9 rebilling, these unnecessary transactions strain ERCOT resources and, where any 10 manual input is involved, potentially gives rise to errors and rejected transactions. 11 Q. WHAT COSTS ARE IMPOSED DIRECTLY ON REPS AND THEREBY 12 INDIRECTLY ON END-USERS? 13 A. The REP now bears the customer relations costs associated with the inquiring, 14 unhappy or complaining customer. There is also an expected cost to checking the 15 accuracy of the estimated meter read. TCC proposes to charge $17.00 as a Special 16 Meter Reading Fee. The tariff says the REP will not be charged for a re-read if the 17 new reading indicates the original reading was in error. So, the REP faces an 18 uncertain cost of $0 or $17. During the test year, TCC earned $385, 735 on 25,716 19 occurrences where the REP took the gamble and lost.32 Said differently, the REP 20 may have mixed incentives for following up with a re-read request on an estimated 21 bill (regardless of whether the REP or the end-use customer will pay). 32 Response to Cities 23-4, Attachment. DIRECT TESTIMONY 53 GOODFRIEND As discussed previously, costs placed on REPs must ultimately be passed to 2 end-use customers. Even so, the costs imposed on REPs still have an effect. They 3 will affect the REP's perceptions of the ultimate costs of serving the customer, and 4 thereby affect REP's pricing and service offers and possibly decisions about when or 5 whether to enter or remain in TCC's market area. 6 Q. CAN YOU QUANTIFY ANY OF THE COSTS YOU'VE CONSIDERED 7 HERE? 8 A. I can illustrate some of the potential costs. Remember that TCC will incur some costs 9 too. The alignment problem is that TCC considers only its net savings, in this case 10 estimated to be $5/estimated meter read, when deciding policy on the extent to use 11 estimated meter reads. My point is simply that when the potential costs to all 12 other parties are considered, if these costs exceed TCC's net $5 saving per 13 estimated meter read, TCC has made the wrong customer service decision based 14 on the alignment standard. An illustration of costs imposed on others by the 15 change in meter reading policy toward estimated meter reads appears below: The 16 "x"s reflect the distribution of costs and the "Illustrative Unit Costs" column provides 17 hard estimates from discovery information. So, for example, the "x" across from the 18 Call Center Calls row in the end-user cost column and the REP cost column identifies 19 the fact that both of these parties may incur these kinds of costs. DIRECT TESTIMONY 54 GOODFRIEND 1 Figure 8 550, 000 Additional Estimated Meter Reads--Potential Market Costs Impacted Parties End-User REP Market and PUCT Additional Transactions Required Illustrative Unit Costs Costs Costs Costs Inspect and Determine Action ? x x Cancel and Rebill - electronic 1 minx 40/hr = 0.66 x x Cancel and Rebill - manual 15 minx 40/hr =$10 x Call Center Calls 3.5 minx 1.00 x x Calls Forwarded 8 minx 1.00 x Field Rep Trips $17 /no error xi Ix High Bill Complaint Customer Service 1hrx34/hr x x Opportunity Costs of Time ? x Higher Market Prices ? x x Bill "surprise" and Degradation of REP reputation ? x x x Delayed Bill x x "?"signifies difficult to quantify costs Estimates from Response to Cities 15-2 Attachment l And Schedule IV J-2 p. 18 2 3 4 Q. EARLIER YOU STATED THAT HIGH LEVELS OF ESTIMATED METER 5 READS COULD BE EXPECTED TO LEAD TO MORE CANCEL AND 6 REBILL TRANSACTIONS FOR METERS AND INVOICES. 7 A. Yes. The available data for TCC demonstrates this. In the data below, I have had to 8 combine two incomplete series -- one provided in discovery and the other based on 9 confidential and privileged information. 10 Q. IS THE DATA ON CANCELLATIONS CONSISTENT WITH ESTIMATED 11 METER READS AS ONE REASON FOR THE LEVEL OF 12 CANCELLATIONS AND REBILLINGS? 13 A. Yes. 14 [FIGURE 9 REDACTED] DIRECT TESTIMONY 55 GOODFRIEND 1 Q. HOW MANY CANCEL/REBILL TRANSACTIONS DO THE 2 PERCENTAGES IN FIGURE 9 REPRESENT? 3 A. TCC sends out about 1 million bills annually. So a [redacted] rate of cancel/rebills is 4 [redacted] cancel/rebill transactions annually. 5 SLOW OR NO GO ON FASTRAK RESOLUTIONS 6 Q. WHAT ARE FASTRAK ISSUES AND WHY ARE THESE IMPORTANT IN 7 DEFINING SERVICE QUALITY? 8 A. FasTrak is an issues-resolution system sponsored by ERCOT. FasTrak is the primary 9 tool and entry system used by REPs and TDSPs to communicate with ERCOT 10 regarding problems with electronic customer enrollment. Problems reported through 11 FasTrak could include, for example, missing usage data or other information not in 12 the ERCOT system that is associated with a customer/premise location, rejected 13 transactions, requests for cancellation of transactions, inadvertent switches, or 14 whether or not ERCOT received a specific transaction, etc. 15 For issues submitted to ERCOT, ERCOT will follow up with the TDSP for 16 thirty days to obtain requested transaction(s). After thirty days, the issue will be 17 reassigned as a Non-ERCOT issue, and the submitting REP and TDSP will be left to 18 continue efforts to resolve. Alternatively, some issues are initially submitted as Non- 19 ERCOT when the issue is "point-to-point" between a REP and a TDSP). No FasTrak 20 issue is deleted. Resolved or rejected issues are archived and available for search 21 purposes.33 33 ERCOT FasTrak Day-to-Day User Manual -- Version 4.0 available from www.ercot.com. DIRECT TESTIMONY 56 GOODFRIEND 1 REPs depend on TDSPs to take responsibility for Non-ERCOT issues and to 2 assign sufficient resources to help resolve all FasTrak issues promptly. Resolution 3 also requires good communication because ERCOT will not generate missing 4 transactions when manual corrections are needed. 5 Q. WHAT GENERAL EXPLANATIONS DID REPS PROVIDE FOR THEIR 6 RANKINGS OF TCC IN THIS AREA? 7 A. Being quick to resolve FasTrak issues is the key service quality dimension for 8 FasTrak. Two REPs made this point, stating that TCC was slow to respond to 9 FasTrak issues. A customer with "very few customers in AEP territory" said: TCC is IO generally responsive to FasTrak issues, however they rarely answer their 800-line for 11 REP support and are very slow to respond to emails and voicemails. 12 Another REP linked the slow response to lack of dedicated resources: The 13 personnel that are working FasTrak are very helpful and knowledgeable but seem 14 overwhelmed with the volume of FasTrak issues requiring their attention. [TCC 15 needs] more trained personnel. 16 Q. DID YOU RECEIVE ANY SPECIFIC EXAMPLES? 17 A. Yes. A respondent commented: TCC is generally quicker than other TDSPs to 18 acknowledge new logged FasTrak issues. However, once acknowledged, there is an 19 average resolution time of 3 weeks, with outliers up to 8 weeks. We have noted that 20 TCC is quicker to respond to logged FasTrak issues relating to enrollment and less 21 responsive to ongoing maintenance issues related to monthly meter reads and ES! ID 22 maintenance issues. Not all survey participants have logged FasTrak issues with DIRECT TESTIMONY 57 GOODFRIEND 1 TCC so some answered the survey questions with N/A. The remaining responses are 2 provided below. Figure 10 Dimensions of Service Quality Responsiveness Quality and in Resolving Timeliness of Speed of Pro· Dedication Accuracy FasTrak Issues Communication Response active of of Problem Resources Response Solving We have very few Timeliness is the The personnel that TCC Practice customers in AEP biggest issue with are working FasTrak territory ... AEP is generally FasTrak are very helpful and responsive to FasTrak resolution. TCC is knowledgeable, but issues, however, they rarely slow to respond seem overwhelmed answer their 800-line for to Fas Trak issues with the volume of REP support and are very (2 responses) Fas Trak issues slow to respond to emails requiring their and voicemails. TCC is generally attention. Need more quicker than trained personnel. Not many issues for us other TDSPs to since we have so few acknowledge new customers in territory. logged FasTrak Issues generally resolved in issues. However, a timely, accurate matter. once acknowledged, there is an average resolution time of 3 weeks, with outliers up to 8 weeks. We have noted that TCC is quicker to respond to logged FasTrak issues relating to enrollment and less responsive to ongoing maintenance issues related to monthly meter reads and ESI ID maintenance issues. DIRECT TESTIMONY 58 GOODFRIEND Other TDSPs keep you well Timeliness is key Same day Other TDSPs provide (See response in Best Practice informed on the status of to resolving response, direct contacts and Column 3) Standards/ FasTrak issues and respond issues on knowledgeable personnel very quickly. FasTrak. Other and well- representatives. Suggestions for TDSPs are trained Reps, Improvement It is much easier to call a extremely update Recommended CSR contact at the other proficient in FasTrak ticket Action: TDSPs and not get voice processing without having Assignment of a mail. Also, callbacks are requests in a to be asked, customer much faster when you do timely manner. notify representative for our leave a message. monitoring company. Others often have party by email same day when action Best Practice is resolution. They has been Achievable by TCC are much quicker, taken/ticket [with] training and requiring a few updated, operation al efficiency days or at most a resolving week. action is Yes, if their staffing is accurate. adequate. 1 2 Q. DO YOU HAVE EVIDENCE CORROBORATING THAT TCC IS SLOW ON 3 FASTRAK? 4 A. Yes. As indicated above, ERCOT personnel are also involved in FasTrak issues. 5 Among the many reports that ERCOT personnel present at the monthly ERCOT 6 Retail Market Subcommittee (RMS) meetings is a report on FasTrak activities. The 7 most recent available evidence suggests that TCC is slow on resolving its FasTrak 8 issues with ERCOT. 9 Q. PLEASE EXPLAIN. 10 A. Here too, it is necessary to briefly discuss what is involved in making certain market 11 transactions succeed. ERCOT periodically receives from TDSPs final monthly meter 12 reads and notifications of an initial meter read on service orders that have been 13 cancelled in ERCOT service order recording systems. ERCOT recognizes various 14 types of service order cancels. ERCOT cancels service orders when it receives cancel 15 requests from the REP (perhaps due to manual or concurrent re-processing of the 16 original service order), cancel requests due to customer request, customer objection DIRECT TESTIMONY 59 GOODFRIEND 1 (e.g., during the switch rescission period, the customer exercises the right not to 2 switch providers), cancels due to a necessary permit not being received (e.g., on a 3 move-in transaction where construction may be needed) or for other reasons. That 4 the TDSP has sent ERCOT a meter read for this service order can indicate an "out-of- 5 sync" condition in which TDSP records and ERCOT records may fail to agree on 6 which REP is providing service. 7 To manage these situations, ERCOT initiated a process on November 7, 2003. 8 In this process, ERCOT initiates a weekly FasTrak issue with the appropriate TDSP 9 as the resolving party for these transactions. ERCOT requests the TDSP to provide a 10 response either updating the FasTrak issue if the service orders are canceled in the 11 TDSP system or, if complete in the TDSP system, identify the out-of-synch condition 12 with ERCOT and initiate an effort to clear the out-of-sync conditions. 13 With respect to these November 7, 2003 cancelled service orders, the last 14 column of the second table below indicates that among the four major TDSPs TCC is 15 the only TDSP with ERCOT still waiting for responses as of the January 14, 2004 16 Report. The following figure is Figure 11. DIRECT TESTIMONY 60 GOODFRIEND TDSP Tot.:il '12/31103 12/19/03 '12/12103 1215;03 'l'l/28/03 '11/21/03 '11/14103 11/7,03 AEP '127 12 23 23 9 12 10 34 4 Cente1Pnint 237 16 31 20 18 34 34 67 17 ONCOR 287 '14 '166 1'I 14 26 32 '16 8 Sh.11 vi.ind 17 2 2 2 3 3 0 2 3 TNMP 275 '12 94 92 21 '17 '17 '16 6 G1 .1nd Total 943 56 3'16 148 65 92 93 '135 38 Cancelled comp1etea byTDSP byTDSP Awaiting TDSP TDSP Total (In-Sync) (Out-of-Sync) Response AEP 127 9 51 67 CenterPoint 237 164 73 0 ONCOR 287 187 100 0 Sharyland 17 0 8 9 TNMP 275 275 0 0 Grand Total 943 635 232 76 1 2 The full ERCOT presentation is provided in Workpapers. 3 Q. DID REPS HAVE ANY RECOMMENDATIONS FOR TCC THAT YOU 4 HAVE NOT INCLUDED IN SECTION I OF YOUR TESTIMONY? 5 A. Yes. These were generally specific requests for better performance on the service 6 quality dimensions. REP suggestions to TCC not already captured in my specific 7 recommendations are that TCC should: 8 • provide faster customer service; 9 • respond at first request rather than requiring multiple contacts; 10 • be more pro-active informing REPs about changes to procedures; 11 • provide additional/more knowledgeable and qualified personnel to respond to 12 inquiries or issues; DIRECT TESTIMONY 61 GOODFRIEND 1 • provide additional educational programs regarding TCC's internal processes and 2 procedures; 3 • provide historical usage in a user friendly format; and 4 • provide quicker turnaround on IDR and non-IDR data. 5 C. REBUTTAL TO TCC WITNESSES GORDON AND HOOPER 6 1. ISA SERVICE QUALITY 7 SUMMARY FINDING 8 Q. HA VE YOU REVIEWED ALL THE REPORTS FILED WITH THE PUCT 9 PURSUANT TO TCC DUTIES TO REPORT THE CUSTOMER SERVICE 10 STANDARDS THAT TCC NEGOTIATED IN THE ISA? 11 A. Yes, and I have done additional discovery on these matters. 12 Q. WHAT IS YOUR OVERALL IMPRESSION OF TCC'S PERFORMANCE ON 13 ISA REQUIREMENTS? 14 A. TCC owes fines in the form of customer credits based on inability to satisfy targets 15 that its predecessor companies had a hand in negotiating.34 As is clear from review 16 of its required reports, TCC has not been able to demonstrate sustained or full 17 compliance with negotiated targets. TCC's offers to fix reporting problems that 18 "explain" the non-compliance are still promises rather than realities. 34 See Direct Testimony of Dr. A. D. Patton. DIRECT TESTIMONY 62 GOODFRIEND 1 WITNESS GORDON 2 Q. PLEASE SUMMARIZE THE INTEGRATED STIPULATION AND 3 AGREEMENT (ISA) WITH RESPECT TO CUSTOMER SERVICE (NOT 4 RELIABILITY) ISSUES. 5 A. The Integrated Stipulation and Agreement was entered into by TCC's predecessor 6 companies in May 1999. Included within the ISA in Section 7 are Customer Service 7 Standards as well as the Reliability Standards discussed in the testimony of Cities 8 Witness Dr. A.D. Patton. TCC Witness Gordon provides ISA Section 7 in his Exhibit 9 HRG-4. 10 Q. WHAT KIND OF CUSTOMER SERVICES ARE MEASURED IN THE ISA? 11 A. The agreement provides for measurement in four areas: (1) a time-to-connect 12 standard for new service installation where no construction is required, and (2) where 13 installation construction is required, a time-to-connect standard for (a) standard 14 facility construction and (b) a time-to-connect standard for non-standard facility 15 construction. There is also a time-to-restore/replace standard for (3) security and 16 streetlight outages, and time-to-average-answer standard for (4) telephone response of 17 call center employees. 18 Q. DID YOU REVIEW THE TESTIMONY ON ISA STANDARDS OF TCC 19 WITNESS GORDON? 20 A. Yes. Mr. Gordon describes performance in the areas of new service requiring 21 standard construction and non-standard construction and with respect to lighting 22 replacement for outages, what I have called items 2(a and b) and Item 3 above. DIRECT TESTIMONY 63 GOODFRIEND 1 As Mr. Gordon shows, TCC has failed to meet target for new service 2 involving standard construction in the third and fourth quarters of 2002 and in every 3 quarter reported thus far for 2003. He blames the problem on a newly initiated 4 automated customer information system. And, he is convinced that the problem lies 5 in the reporting system rather than performance. 6 Q. HAS TCC FIXED ITS REPORTING SYSTEM FOR TRACKING STANDARD 7 CONSTRUCTION TIME-TO-CONNECT? 8 A. Mr. Gordon reports that problems still exist with the reporting system. Although a 9 discovery response now asserts the reporting system has been fixed, the assertion is 10 based on the "planned implementation" of new software and order management 11 systems.35 12 Q. DOES MR. GORDON REPORT PERFORMANCE FOR NON-STANDARD 13 CONSTRUCTION REQUESTS? 14 A. Yes. He minimizes the failure to meet targets by explaining that there are very few 15 requests of this nature. 16 Q. WHAT ABOUT LIGHTING REPLACEMENTS? 17 A. Here again, TCC does not meet targets but feels that reporting problems are to blame. 18 In response to a follow-up question, TCC explains that the order tracking 19 system identified by Mr. Gordon36 is still unable to differentiated between standard 20 and non-standard lighting replacement. A procedural change relying on functionality 35 Response to Cities 29-13. Moreover, the discovery response suggests that, to the extent that TCC may subjectively evaluate "customer readiness," TCC may reset this variable thereby restarting the clock. Full discovery responses to Cities 29-13 are provided in Workpapers as is Response to Cities 16-21 which identifies the readiness requirements. 36 Direct Testimony of Mr. Gordon at 34. DIRECT TESTIMONY 64 GOODFRIEND 1 to be implemented should be able to report actual performance by the last quarter of 2 2004. 3 Q. HOW DO YOU CHARACTERIZE PERFORMANCE ON THE TWO AREAS 4 DISCUSSED BY MR. GORDON? 5 A. Like the filed reports, for each failure, the reporting incident brings with it either an 6 excuse, a promise, or evidence of a promise unkept. These excuses and explanations 7 also characterize Mr. Gordon's testimony. 8 REPORTED PERFORMANCE FOR THE ISA 9 Q. WHAT ARE THE REPORTING REQUIREMENTS OF THE ISA? 10 A. The ISA imposed three annual reporting requirements: a Customer Service Survey of 11 Texas Customers and a Customer Service Report to be filed with the PUCT, and a 12 Utility Scorecard to be sent to its customers. A fourth report to the PUCT is triggered 13 by failure to meet minimum service standards for any two months within a 12-month 14 period. 15 Q. HAS TCC BEEN ABLE TO CONSISTENTLY MEET THE TARGETS IT 16 NEGOTIATED FOR ITSELF IN THE ISA? 17 A. No. 18 Q. PLEASE EXPLAIN. 19 A. First, TCC never filed all the reports contemplated by the ISA. In December 2001, 20 before any annual reports had been filed, TCC filed a petition requesting modification 21 of the standards in the ISA. By agreement with Staff, TCC was permitted to forego 22 providing the ISA-required Annual Utility Scorecard to customers. So, in February 23 2002, TCC filed 2001 data for the other two annual reports. DIRECT TESTIMONY 65 GOODFRIEND 1 (1) 2001 data 2 Q. WAS TCC IN COMPLIANCE WITH ALL ITS ISA TARGETS? 3 A. No, TCC was not in compliance for light replacement. TCC explained that the data 4 was contaminated by inclusion of more complex repairs that those called for in the 5 performance measure. TCC opined that a system modification in January 2002 6 would allow TCC to demonstrate better, and presumably, compliant performance. 7 Q. WERE THERE OTHER INCIDENTS OF NON-COMPLIANCE? 8 A. Yes. In April, 2001 TCC notified the PUCT that it had experienced three months in a 9 row where average speed of answer was too slow, relative to the target. TCC 10 identified the combination of extreme weather, rising gas prices and changes in the 11 volume, duration and nature of calls as causes. 12 (2) 2002 data 13 Q. WHAT ABOUT 2002 DATA? 14 A. TCC was out of compliance for both lighting replacement and for connection 15 requiring standard installations. In February 2003, TCC filed its 2002 data under 16 agreement with Staff that TCC provide only the same information as TCC provided 17 in 2001. Although TCC had modified its work order system in January 2002, TCC 18 was again unable to demonstrate compliance or improved lighting replacement 19 performance as predicted/ hoped for last year in TCC's explanatory comments. The 20 measure for connection requiring standard installation was also out of compliance. 21 TCC explained that the conversion from the CSW to the AEP Customer 22 Information System (known as Marketing And Customer Services System), combined 23 with workarounds necessitated by electronic exchange problems under Customer DIRECT TESTIMONY 66 GOODFRIEND 1 Choice had resulted in the need to reconstruct lost data such as construction 2 completion dates. Thus, the reported 2002 data for connection times for standard and 3 nonstandard installation was based on recollections of people in the field, and so, not 4 totally accurate. 5 WITNESS HOOPER 6 Q. WHAT MEASURES DOES WITNESS DAVID L. HOOPER DISCUSS? 7 A. He discusses what I have called Item 4, "time-to-average-answer standard for 8 telephone response of call center employees." Presumably he also discusses what I 9 have called Item the " time-to-connect standard for new service installation where no 10 construction is required." 11 Q. WHY DO YOU SAY "PRESUMABLY"? 12 A. Because Mr. Hooper does not report the proper measure for time-to-connect, as 13 contemplated in the ISA. I discuss this below. 14 Q. WHAT IS THE FIRST MEASURE MR. HOOPER DISCUSSES IN HIS 15 TESTIMONY? 16 A. The target for average speed of answer (ASA) set by the ISA is within 60 seconds. 17 As I discussed above, under certain stresses, TCC was unable to satisfy the standard, 18 and had to provide an improvement plan to the PUCT as required by the ISA. 19 Q. WHAT ARE THE RESULTS OF THE IMPROVEMENT PLAN? 20 A. Using the Virtual Call Center, Mr. Hooper suggests, TCC has been able to drop the 21 ASA to 38 seconds, year to date. However, since then the ASA seems to be creeping 22 up again. The updated ASA through 12/31/04 is 42 seconds. DIRECT TESTIMONY 67 GOODFRIEND 1 Q. AVERAGES ARE NICE. DOES VARIANCE MATTER? 2 A. Yes. As in the April 2001 event, TCC has not consistently met target in all months. 3 Arguably it is most important to have a timely response when the system is under 4 stress from external events that are generating the customer calls. Events in October 5 2003 forced the monthly average above the target, suggesting that consistency of 6 achievement on the ASA target is still in some question.37 7 Q. WHAT IS HIS SECOND MEASURE? 8 A. Mr. Hooper uses the term "existing meter" connects, and then asserts that this is what 9 is supposed to be measured by the ISA. The ISA doesn't use this term. An "existing 10 meter" connect is a "left in hot" or energized meter. TCC has a fully automated 11 process for connecting these meters on a move-in or switch transaction, if they have a 12 meter reading within five days prior to the requested date.38 And, we know if they 13 don't, they can complete the automated process, keeping these performance statistics 14 up, by use of an estimated meter read. 15 The question, of course, is what happens with more difficult move-m 16 transactions. Thus, we really don't know whether TCC is meeting the 95% target 17 when the reported data is properly expanded to include all new service installations. 18 Moreover, TCC reports that it is exceeding the PUCT target of 95% in Subst. 19 R.§25.490. Subst. R. §25.490 governs the ending of the moratorium on disconnects 20 which the PUCT instituted early on to address re-connection problems. Here again, 21 TCC is describing a left-in hot or energized meter situation. Like all the other TDSPs 37 Response to Cities 30-14 Attachment 1. 38 Response to Cities 16-20. DIRECT TESTIMONY 68 GOODFRIEND 1 who report on this measure, TCC is meeting this target for reconnection on energized 2 meters. TCC is reporting a measure based on less than full scenarios. 3 TCC REPORTED BILLING ACCURACY MEASURE 4 Q. DOES MR. HOOPER REPORT ANY OTHER STATISTICS? 5 A. In addition to his ISA reporting, Mr. Hooper reports a measure he describes as the 6 percentage of bills that require no adjustments and indicates that for the period 7 January through August this number is 98.74%. The 2003 measure is 98.78%.39 He 8 claims that this statistic is a good indicator of meter reading and billing success. 9 Q. WHAT DO YOU MAKE OF HIS CLAIM? 10 A. First, there is no definition showing how the statistic is constructed and what data are 11 used. Although Mr. Hooper provides no definition for his statistic, it appears to be 12 the same statistic that TCC has reported previously as the one measure TCC decided 13 to include in the ISA reports to the PUCT that was not specifically asked for: the 14 BILLADJ measure. Perhaps, BILLADJ was provided in response to a general ISA 15 request to include billing error information. 16 Second, if this is BILLADJ, it is interesting to notice that this measure, unlike 17 the other ISA reported measures, shows very little variability: For 2001 the statistic 18 is 99.79. For 2002 the statistic is 99.86. For 2003, through August, as reported by 19 Mr. Hooper, the statistic is 98.74 and updated for all of 2003, the statistic is 98.78. 20 For example, if BILLADJ is measuring every bill that TCC sends, not just bills based 21 on meter reads to retail customers, but a larger universe of billings, then one would 22 expect this statistic to behave as it does. That is, the reason it has such low variability 39 Response to Cities 30-13. DIRECT TESTIMONY 69 GOODFRIEND 1 may be because, as a statistical measure, BILLADJ isn't really providing much 2 information of value from the perspective of assessing regulated utility billing quality. 3 Third, if my suppositions above are all wrong, then I will simply point out that 4 TCC is not currently meeting its Texas target for BILLADJ, which TCC reported in 5 its 2001 ISA filing to the PUCT as being 99%. 6 And fourth, other billing data provided by TCC in discovery, some filed 7 confidentially and some not, indicate less than 99% billing accuracy when what is 8 being measured is the sending of bills to REPs. The reported measure here is simply 9 inconsistent with utility-specific data on estimated meter readings, cancellations and 10 rebillings, etc. provided to me by TCC in this proceeding. 11 2. SERVICE QUALITY REPORTING: RECOMMENDATION 12 Q. DO YOU HAVE ANY CONCLUDING REMARKS FOR THIS SECTION? 13 A. First, confidential reporting of TDSP performance measures is contrary to good 14 regulation and results solely from an anomaly created in drafting the rule rather than 15 from regulatory intentions. The reporting of performance measures by regulated 16 utilities is a tool for regulation, not a means to secrecy. The intention of Subst. R. 17 §25.88 is not to put information concerning a regulated TDSP with no competitors 18 and subject to rate regulation on par with information pertaining to competitive 19 entities such as REPs. For example, none of the ERCOT performance measures are 20 confidential because ERCOT files on behalf of itself. That ERCOT also files on 21 behalf of the TDSPs has created the anomalous result that information pertaining to DIRECT TESTIMONY 70 GOODFRIEND 1 TDSP performance requested by the Commission is not available for analysis to 2 anyone other than Staff able to review the confidential filings.4° 3 Second, public reporting of TDSP performance measures is in the public 4 interest. The public reporting of TDSP performance information can create 5 benchmarks for further assessment and identification of the most pressing problems 6 by those who have an interest in seeing performance problems identified and fixed. 7 Thus, the Commission should direct TCC to file as non-confidential the "B 8 Report" portion of TCC's Quarterly Performance Report that ERCOT now files 9 confidentially on behalf ofTCC. 10 III. REQUEST FOR GOOD CAUSE EXCEPTION 11 A. NEITHER ABD O&M SERVICES NOR TRANSMISSION 12 CONSTRUCTION SERVICES COMPLY WITH SUBST. R. 13 §25.342(f)(D) OTHER SERVICE 14 15 1. REGULATED UTILITY PROVISION OF UNREGULATED 16 SERVICES: DEFINITIONS AND DISTINCTIONS 17 18 LEGAL FRAMEWORK 19 20 Q. WHAT FRAMEWORK WILL YOU USE TO EVALUATE TCC'S REQUEST? 21 A. I will be using the Substantive Rules governing Unbundling. Specifically, I will be 22 discussing §25.341 "Definitions" and §25.342 "Electric Business Separation," and in 23 particular, § 25.342 (f) "Separation of transmission and distribution utility services," 24 of which the "Other service" rule is a part. 40 This is data reported by ERCOT on the TDSPs behalf. ERCOT may send or sends this data to the TDSP under its right to contest the accuracy of the ERCOT Report. ERCOT must report TDSP information as confidential since any information relating specifically to any other entity (unless the Commission determines otherwise) must be confidentially reported. See Filing Requirements For Performance Measure Reporting Pursuant to PUC Subst. R. 25.88. DIRECT TESTIMONY 71 GOODFRIEND APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 2005 WL 6472784 (Tex.P.U.C.) Slip Copy APPLICATION OF AEP TEXAS CENTRAL COMPANY FOR AUTHORITY TO CHANGE RATES PUC Docket No. 28840 SOAH Docket No. XXX-XX-XXXX Texas Public Utility Commission 2005 ORDER Before Hudson, Chairman, Parsley, and Smitherman, Commissioners. BY THE COMMISSION: This Order addresses the application of AEP Texas Central Company (TCC) for authority to change its rates. TCC initially filed its application on November 3, 2003, seeking approval of a revenue requirement of $519.9 million. For the reasons discussed in this Order, the Commission determines that TCC's appropriate revenue requirement is $443,607,238. The reduction reflects an agreed disallowance of $10.5 million in affiliate expenses, as well as additional disallowances as determined by the Commission. As allocated, the distribution portion of TCC's current revenue requirement will increase by $5.3 million, whereas the wholesale transmission portion will decrease by $14.1 million. As discussed in this Order, the Commission adopts in part and rejects in part the proposal for decision (PFD) and remand PFD issued by the State Office of Administrative Hearings (SOAH) administrative law judges (ALJs) in this proceeding, including the findings of fact and conclusions of law. I. Procedural History The Commission referred this case to SOAH on November 4, 2003, and SOAH issued its initial PFD on July 1, 2004. The Commission issued an Order on Remand on July 28, 2004, directing SOAH to consider the appropriate amount for a consolidated tax-savings adjustment, which was not calculated in the initial PFD. On August 25, 2004, the Commission issued a Second Order on Remand, directing SOAH to provide further evaluation regarding the following issues: affiliate costs, distribution administrative and general (A&G) expense adjustments, depreciation expense, net salvage, special meter reading fee, connect fee and service reconnect fee, and priority disconnect fee. SOAH issued its Remand PFD on November 16, 2004. The Commission considered the initial PFD and the Remand PFD at its January 13 and January 27, 2005 open meetings. The Commission determined at that time that the issues of merger savings, affiliate costs, and distribution A&G expense adjustments needed additional consideration and held a hearing on March 3, 4, and 7, 2005 to develop a further understanding of the record on those issues. Accordingly, finding of fact 20A is added to reflect this additional procedural history. Additionally, finding of fact 20 and conclusion of law 6 are modified to reflect TCC's waiver of the effective date to allow the Commission additional time to hold this hearing and to complete its deliberations. 1 This Order combines the findings of fact and conclusions of law from both the initial and the remand PFDs, as well as those added by the ALJs pursuant to their letter of clarifications and changes filed on August 19, 2004. Thus, the remand findings of fact and conclusions of law are inserted in the appropriate location and designated with an “R” followed by its Remand PFD number, while the Commission's amended findings of fact and conclusions of law are designated with the traditional “A,” “B,” etc. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 1 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... II. Discussion A. Merger Savings In Docket No. 19265, 2 the Commission approved the merger of American Electric Power Company (AEP) and Central and Southwest Corporation (CSW). In approving the merger, the Commission adopted the Integrated Stipulation and Agreement (ISA), which was an agreement among a majority of the parties to the case that reflected numerous commitments made by AEP regarding merger-related issues. Among those commitments was a regulatory plan that provided for net merger-savings rate-reduction riders, which reduced rates to customers by annual, pre-determined amounts. Additionally, the regulatory-plan portion of the ISA provided for a “net merger savings” expense item designed “to prevent ratepayers from receiving their share of merger savings twice and to ensure that shareholders retain their share of net merger savings.…” 3 This expense item was limited by a provision that applies if a Texas operating company initiates a rate case. Specifically, Section 3.F.(3) of the ISA provides the following: (3) In any proceeding initiated by a Texas operating company requesting an increase to overall base rate revenues to become effective prior to the end of the six year period after the date of the merger: (a) The net merger savings expense item and annual amount of amortization costs to achieve the merger will not be included in the calculation of the cost of service unless the Texas operating company demonstrates: (i) that the proposed rate increase results from circumstances not directly or indirectly related to the merger; and (ii) that the full level of achieved merger savings for the applicable year as reflected in Attachment D have been achieved; and (b) the revenue requirements otherwise determined to be reasonable and necessary will be reduced by the annual amounts included in Attachment E. As stated previously, this section applies only if TCC initiated a proceeding requesting an increase to overall base-rate revenues. The PFD determined that TCC initiated such a proceeding, and the Commission affirms that finding. Pursuant to Section 3.F. (3), TCC requested an increase to overall base-rate revenue, and thus initiated the rate case. Had TCC come to the Commission to defend its current rates, or requesting a rate decrease, it would not have been subject to this provision. The next inquiry is to determine whether the proposed rate increase results from circumstances not directly or indirectly related to the merger. The ALJs found that the proposed rate increase did not result from circumstances directly or indirectly related to the merger, and the Commission also affirms that finding. In addition to this query, Section 3.F.(3)(a)(ii) requires that TCC demonstrate that the full level of merger savings, as reflected in Attachment D to the ISA, have been achieved. In presenting its case on whether merger savings were achieved, TCC relied heavily on the testimony of its witness Michael Heyeck, who in turn relied on the study completed in Docket No. 19265 by witness Thomas Flaherty. Mr. Heyeck projected total electric operations and management (O&M) costs (adjusted to exclude purchased power, fuel, and factoring of accounts receivables) on a stand-alone basis beginning with actual 1997 data. The adjusted balance was calculated using a weighted- average composite rate from escalators employed by Mr. Flaherty in Docket No. 19265. These escalators reflect increases of 3% for general inflation, 4% for wages and salaries, and 5% for certain other professional services. After performing his calculations, Mr. Heyeck determined that the gross merger savings for the test year were $27.7 million. 4 Additionally, TCC's witness David Carpenter presented testimony of large-scale corporate savings throughout AEP as a result of the merger. 5 A chief criticism of the intervenors' was that Mr. Heyeck relied on the work product of a former witness who was not called in this proceeding. 6 They further complained that Mr. Heyeck's calculations were faulty and that he failed to use current inflation © 2015 Thomson Reuters. No claim to original U.S. Government Works. 2 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... factors and instead used the same inflation factors used by Mr. Flaherty in 1997. 7 The ALJs agreed with the intervenors and found that TCC did not meet its burden to prove that the company achieved the full level of required merger savings. The Commission disagrees with the ALJs, and determines that TCC did meet its burden of proof to demonstrate that merger savings were achieved. The Commission did not require the company to specifically track merger savings. 8 Thus, there was no requirement that the company provide a detailed cost analysis identifying all merger-related cost reductions. Accordingly, Mr. Heyeck did not improperly rely on the work of Mr. Flaherty, but appropriately used his work to calculate merger savings in a manner compatible with the merger-savings target in the ISA. Consequently, the Commission concludes that the information provided by Mr. Heyeck is sufficient to demonstrate that merger savings were achieved. The merger-savings target contemplated by Attachment D to the ISA, although not directly calculated by Mr. Flaherty, was based on the merger-savings projections made by him in Docket No. 19265. 9 By applying the same inflation rate that Mr. Flaherty used, Mr. Heyeck reasonably projected the appropriate amount of merger savings; applying a different inflation factor would result in a skewed comparison of data. In the absence of a specific directive to track merger savings, the Commission determines that TCC demonstrated not only that the full level of merger savings has been achieved, but also that the savings exceeded the amount required by Attachment D to the ISA. Accordingly, findings of fact 32A and 32B are added and conclusion of law 7 is modified. Additionally, finding of fact 33 is modified to delete the term “affiliate,” and replace it with the term “effective.” B. Rate Base 1. Post-Test-Year Adjustments In its application, TCC sought to add $8.2 million to its rate base for distribution-plant capital expenditures made during the test year for plant placed in service after the test year. Additionally, TCC proposed reducing its rate base by $6.2 million based on an expected sale of certain distributed-related facilities after the test year. The Commission adopts the ALJs' recommendations to disallow TCC's proposed addition to distribution rate base of $8.2 million and to accept TCC's initially proposed reduction to distribution rate base of $6.2 million. In support of this ruling, the Commission recognizes that P.U.C. SUBST. R. 25.231 prescribes different standards for post-test-year additions to rate base than for post-test-year reductions. Specifically, P.U.C. SUBST. R. 25.231(c)(2)(F)(i)(II) requires any such addition to constitute at least ten percent of the utility's requested rate base, whereas P.U.C. SUBST. R. 25.231(c)(2)(F)(iii) contains no such requirement for a rate-base reduction. The asymmetry of these provisions supports the Commission's decision and undercuts TCC's argument that the ALJs' treatment of the addition and reduction was inconsistent. To reflect the different standards in P.U.C. Subst. R. 25.231 for post-test-year additions and reductions to rate base, the Commission adds finding of fact 39A. 2. Coleto Creek Substation TCC requested an addition to plant-in-service of $3,016,482, which was the amount by which the actual cost exceeded the cost estimate included in the utility's original CCN proposal for improving the Coleto Creek substation. TCC argued that the additional improvements were necessary to accommodate the Electric Reliability Council of Texas's (ERCOT's) plans, and that utilities should be encouraged to assist ERCOT in long-range transmission plans. The ALJs observed that the Commission never approved the investment associated with the extra cost, concluded that the underlying design changes were not useful in serving TCC's current customers, and disallowed the extra $3,016,482. The Commission reverses the ALJs' ruling and allows inclusion of all but $180,000 of the $3,016,482 at issue. The Commission finds that TCC prudently re-examined and altered its design plans to accommodate ERCOT's proposal of a Coleto-to-Cuero- to-Holman double-circuit-capable 345-kV line. This proposal was issued after TCC had submitted its original design and cost © 2015 Thomson Reuters. No claim to original U.S. Government Works. 3 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... estimate in the CCN case. 10 As explained by TCC, the original design was selected without regard to the land restrictions of the existing substation site, and construction based on that design would have precluded meeting the facility needs envisioned by ERCOT, absent construction of another substation at another location. 11 According to TCC, such facility-duplicating construction would have cost at least $5 million, resulting in a higher net cost of about $2 million. 12 The Commission further notes that the bulk of the $3,016,482 excess stemmed from the modification of the physical arrangement of the Coleto Creek additions, which in turn required extra spending on structural steel and foundations. 13 According to TCC, only $180,000 of that total is associated with facilities (six extra 345-kV switches) installed to accommodate future 345-kV transmission lines, and hence may be considered not yet in service. 14 The Commission finds that electric utilities should be encouraged to cooperate with ERCOT and make reasonable modifications to Commission-approved plans for facility construction when doing so would avoid costly facility duplication in the foreseeable future. Otherwise, utilities would have an undue incentive to focus strictly on short-term needs. The Commission finds it unwise to encourage such short-sightedness. Accordingly, the Commission disallows only $180,000 of the $3,016,482 in question, and therefore adds findings of fact 46A and 47A, and modifies findings of fact 47 and 245. 15 The Commission also modifies conclusion of law 13 and adds conclusion of law 13A. 3. Cash Working Capital and Factoring Adjustment The ALJs recommended that the Commission set the level of cash working capital (CWC) and associated factoring expense to reflect a much lower factoring ratio than the 100% recommended by Staff and certain intervenors. As noted by the ALJs, factoring is a financial technique by which a company sells some or all of its accounts receivable to a third party rather than collect the payments from its own customers. 16 TCC stated that it currently has no ability to factor its accounts receivable because the banks with which its predecessor, Central Power and Light Company (CPL), dealt previously (and which are the ultimate purchasers of accounts receivable) are no longer willing to factor TCC's receivables. TCC noted three reasons for this unwillingness. First, TCC now bills only a handful of customers (the retail electric providers (REPs)), compared to the hundreds of thousands of customers it billed before unbundling, and the concentration of credit risk in a few receivables is unacceptable to the banks. 17 Second, the REPs have no credit history with the banks versus the many years of predictable history regarding the level of bad-debt expense reasonably expected when TCC was serving end-use customers. Finally, the type of wholesale customers whose receivables that CPL factored before unbundling were municipal and cooperative utilities, who did not present as significant a credit risk as the REPs. The Commission finds that TCC presented persuasive testimony that it had been unable to find any banks willing to factor TCC's receivables because of credit concerns in the restructured Texas market. 18 Accordingly, the Commission reverses the ALJs and adopts TCC's original proposal to calculate its cash working capital on the assumption of no factoring. The Commission's ruling should not be viewed as necessarily applicable to any future rate case of an unbundled transmission and distribution (T&D) utility. In particular, it is possible that as the retail electric market matures, some REPs will develop credit histories sufficient to induce banks to participate once again in factoring arrangements with T&D utilities. In such circumstances, the utility could be required to calculate its cash working capital under the assumption that it factors some or all of its accounts receivable. In accordance with this ruling, the Commission modifies findings of fact 51 and 52 and deletes finding of fact 53. C. Cost of Service 1. Affiliate Costs © 2015 Thomson Reuters. No claim to original U.S. Government Works. 4 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... TCC originally requested $63.8 million in affiliate expenses. In the initial PFD, the ALJs recommended specific allowances and disallowances in certain instances. However, after the ALJs discussed the itemized allowances and disallowances, they stated that the “Applicant has not carried its burden of proving the entirety of its affiliate costs. Specifically, we conclude that for many of the individual items the Applicant did not overcome the statutory presumption against inclusion.” 19 The ALJs then stated that they were “hesitant to remove an income stream that may be necessary to maintain the ratepayers' level of service and to maintain the Applicant's financial viability.” 20 Ultimately, they recommended a $10.3 million disallowance, based on Dr. Dennis Thomas' testimony. 21 Recognizing that PURA 22 provides that the Commission may not allow affiliate costs unless it has made a specific finding of the reasonableness and necessity of each item or class of items, 23 and that a disallowance of all affiliate costs is required where a utility has failed to meet its burden of proving that its rates are just and reasonable, 24 the Commission remanded the issue of affiliate costs to SOAH for further consideration. The Commission directed that for costs that the ALJs recommend allowing, that the ALJs make specific findings, supported by the evidentiary record, that the costs are reasonable and necessary. The findings should be made on an item-by-item or class-of-item by class-of-item basis. Further, for those items or classes of items for which the ALJs find the Applicant did not meet its burden, the Commission requests a discussion of the deficiency of the evidence that led to such a finding. 25 In their Remand PFD, the ALJs' primary recommendation did not include specific findings on an item-by-item or class-of- item by class-of-item basis. Instead, they recommended adopting Dr. Thomas's position that $53.4 million in affiliate costs be disallowed as TCC did not provide comparisons to demonstrate that each item or class of items was reasonable, necessary, and not higher than prices charged to others, as set forth in PURA § 36.058. In making this determination, the ALJs concluded that the provisions of PURA § 36.058(d) relate to each of the two findings required in PURA § 36.058(c). Thus, the Commission must take into account quantity, terms, date of contract, place of delivery, and allow for appropriate differences in making each of those findings. Thus, the legislature requires evidence of comparability as an element not only of the not-higher-than requirement, but also of the reasonableness and necessity requirements. 26 Expressing concern that the Commission may not agree with their analysis, the ALJs provided an alternative recommendation “based on an item-by-item or class-by-class review of each of TCC's proposed affiliate costs.” 27 The Commission did not agree with the ALJs' analysis of PURA § 36.058(d), and was hesitant to adopt either the primary or the alternative recommendations proposed by the ALJs on this issue. Thus, in order to fully understand the record evidence on this issue, the Commission conducted its own hearing to further evaluate the evidence that TCC presented on its affiliate costs. Before the Commission made its final decision on whether TCC met its burden of proof on affiliate expenses, TCC and Texas Industrial Energy Consumers (TIEC) filed a nonunanimous stipulation (NUS) that provided for a disallowance of $10.5 million. 28 Many parties did not oppose the NUS, 29 but three parties did: the Office of Public Utility Counsel (OPC), CPL Retail, and Texas Legal Services Center/Texas Ratepayer's Organization to Save Energy (TLSC/Texas ROSE). None of the parties opposing the NUS requested a hearing on the settlement. 30 In opposing the NUS, CPL Retail now argues that its “top-down” approach may be in jeopardy as a result of the passage of Senate Bill 1668, 31 and that if the Commission instead uses a “bottom-up” approach, the evidence would support a larger disallowance than that realized through the NUS. 32 OPC argues that the NUS will result in a rate increase to distribution customers and that instead the Commission should disallow between $16.6 and $50 million. 33 © 2015 Thomson Reuters. No claim to original U.S. Government Works. 5 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... The Commission adopts the NUS, and determines that it meets the standards required of a non-unanimous settlement: it complies with applicable law; it is just, reasonable, and in the public interest; and it is supported by a preponderance of the record evidence. 34 The arguments set forth by OPC and CPL Retail are not persuasive. Although in their initial direct testimony, both Cities and CPL Retail argued that the lack of evidence provided by TCC on its affiliate expenses could have supported a disallowance of nearly the entire amount requested, neither party fully advocated that position, and instead recommended a smaller disallowance. The evidence in the record supports adoption of the NUS. The disallowance recommended in the NUS is within the range of that recommended by the intervenor witnesses in this proceeding. OPC's witness Carol Szerszen recommended a total affiliate disallowance of $13,402,570; 35 Cities' witness Gerald Tucker recommended a total affiliate disallowance of $16,572,333; 36 and CPL Retail's witness Dr. Thomas recommended a disallowance of $10,319,991. 37 Additionally, in compliance with PURA § 36.058, the stipulating parties have agreed that, except for the proposed disallowance, TCC's affiliate expenses are reasonable and necessary and that the charges to TCC are not higher than the prices charged by its affiliate, American Electric Power Service Corporation, to its other affiliates or divisions or to non-affiliated persons for the same item or class of items. Finally, the NUS results in a reasonable resolution of this complicated issue. 38 Accordingly, the Commission deletes remand findings of fact R9-R13 and adds findings of fact 69A, 158A-158H, and deletes conclusions of law 26-29 and 72-74. In addition, the Commission modifies findings of fact 55, 39 67 and 71 and adds conclusions of law 25A-25C to reflect this decision. 2. Debt-Reacquisition Costs In its application, TCC sought to include in its rate base approximately $12.5 million in costs resulting from the company's retirement of debt during unbundling. TCC requested that amortization of this amount over a fifteen-year period be included in its cost of service. The ALJs disallowed this item, and held that TCC inappropriately included the entire $12.5 million in this proceeding, rather than allocating this amount to transmission and distribution on the basis of proportionate net book value for the transmission, distribution, and generation functions. The Commission disagrees with the ALJs' determination that TCC's requested recovery of $12.5 million in debt reacquisition costs in this case is inappropriate. The Commission finds that TCC appropriately included the entire $12.5 million in rate base, to be amortized into cost of service over fifteen years. The ALJs and the intervenors rest their determination on an incorrect reading of the Commission's final order in Docket No. 22352, TCC's unbundled cost of service (UCOS) case. 40 In that case, the parties' stipulation resolving the proceeding and the Commission order adopting it stated that debt refinancing costs incurred to restructure CPL were to be deferred and amortized over a fifteen-year period, with the unamortized portion included in rate base. 41 The parties retained the right to challenge the reasonableness of the total amount of debt restructuring costs, as well as the reasonableness of the fifteen-year amortization period. 42 In this proceeding, the parties are challenging neither the amount of debt-restructuring costs nor the reasonableness of the fifteen- year amortization period. Rather, the intervenors' challenge is to TCC's allocation of the $12.5 million in debt-restructuring costs solely to transmission and distribution. The stipulation and order in Docket No. 22352 do not expressly permit the signatories to challenge the allocation of restructuring costs, only their amount and the timing of recovery. Thus, the Commission concludes that the intervenors are precluded from making the argument they now urge in this rate case. Furthermore, the substance of the intervenors' argument is incorrect. The order in Docket No. 22352 did not state that TCC may recover a total amount of debt restructuring charges that must be further allocated between T&D and generation; rather, © 2015 Thomson Reuters. No claim to original U.S. Government Works. 6 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... the debt-restructuring cost discussed in the order reflects an amount already allocated to transmission and distribution. Finding of fact 98 in the Docket No. 22352 order envisioned that these costs would be included in rate base and amortized, and that the parties may only challenge the costs in a future rate case on certain limited grounds. These concepts have relevance only in cost-of-service regulation, under which only CPL's unbundled T&D utility would operate. Therefore, TCC may include approximately $12.5 million in debt-restructuring costs in its rate base, and may amortize the amount into cost of service over a fifteen-year period. The Commission deletes finding of fact 161 and modifies finding of fact 162 to reflect the foregoing discussion. The Commission also modifies conclusions of law 30 and 31. 3. Group-Insurance Expense TCC originally requested $4,649,872 in total group-insurance expenses, an amount which included both $3,741,039 in test-year group-insurance expenses and a post-test-year increase of $908,833. The PFD, as corrected by the ALJs' letter filed on August 19, 2005, recommended inclusion of both the test-year amount and the post-test-year increase. The ALJs cited an actuarial study conducted for TCC and presented by the company in this proceeding as support for the post-test-year increase. The Commission finds that the company's actuarial study provides insufficient support for a post-test-year increase to group- insurance expense. The proper criteria by which to evaluate a requested post-test year increase is the “known and measurable” standard; the Commission has codified this standard in its substantive rules. 43 This standard is not satisfied by an actuarial study that predicts increased group-insurance expense in the future. Such a study, and the cost estimates that derive from the study, are subject to change, and the company itself is not bound to incur the group-insurance expense predicted by the study. Accordingly, the amount that TCC will expend for group insurance after the test year is not currently known or measurable. If TCC desires that the group-insurance expense projected by the actuarial study be included in its cost of service, the company must actually incur those expenses and seek recovery of those costs on a historical basis. Accordingly, the Commission modifies the ALJ's proposed finding of fact 179 and adds finding of fact 179A to reflect that only TCC's test-year group-insurance expense is recoverable through cost of service. Additionally, the Commission modifies conclusion of law 48 to indicate that the expense is includible in TCC's cost of service rather than its rate base. 4. Catastrophe Reserve In its application, TCC sought to increase its catastrophe reserve from $5.4 million to $13.5 million. TCC argued that the increase was necessary because its reserve was virtually depleted as a result of Hurricanes Brett in 1999 and Claudette in 2003. The ALJs, relying on the analysis adopted by the Commission in Docket No. 14965, concluded that the previously approved $5.4 million reserve is adequate. The ALJs noted that TCC has not requested Commission approval to resume the accrual of funds to re-establish the currently approved maximum. Thus, the ALJs rejected the proposed increase and recommended that TCC simply resume its funding to reach the maximum level. The Commission disagrees that the current funding level is adequate. As set forth in TCC's witness Nadel's testimony, there is a 10% probability that the loss in any single year from hurricane damage could be as high as $14 million. 44 The Commission does not, however, agree that TCC's proposed increase to $13.5 million is reasonable. Instead the Commission allows the catastrophe reserve to be funded at $9 million for 10 years. This amount was within the range proposed by the witnesses on this issue. 45 Accordingly, the Commission modifies findings of fact 181 and 181A and conclusion of law 48A to reflect this change. 46 5. Distribution O&M Expense Adjustments © 2015 Thomson Reuters. No claim to original U.S. Government Works. 7 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... The PFD recommended that TCC's request for distribution operations-and-maintenance (O&M) expenses be granted, except that $1.0 million attributed to various other accounts should not be approved, as the ALJs were uncomfortable with TCC's lack of specificity as to this requested amount. 47 The evidence supporting this request was further considered by the Commission at its hearing. At the hearing, TCC demonstrated through Randall Hamlett's rebuttal testimony that the expense was charged to FERC Account 588 during the test year and is includable in cost of service because TCC will continue to incur vehicle- maintenance expense. 48 The Commission reverses the PFD and determines that the $1 million expense for vehicle maintenance was a necessary, recurring expense. Accordingly, the Commission modifies finding of fact 201 and conclusion of law 55. 6. Distribution A&G Expense Adjustments The Commission remanded this item to SOAH to provide further analysis of the basis for the reasonableness of the Applicant's actual A&G expense. The Commission adopts the recommendations contained in the Remand PFD; however, it appears that the ALJs included an incorrect number in finding of fact R16. Accordingly, the Commission modifies this finding to accurately reflect the merger-related revenue-requirement credit of $7,496,000. 7. Third-Party-Contract Margin-Sharing Proposal The ALJs determined that TCC should not be granted a good-cause exception to P.U.C. SUBST. R. 25.342(f)(1)(D)(ii)(III), which requires all revenue from an “other” service to be credited to reduce a utility's cost of service. TCC had requested that it credit only half of the revenues received from its associated business-development program. The Commission agrees with the ALJs' recommendation; however, it further clarifies finding of fact 209 to reflect that TCC's request is denied. Additionally, the Commission modifies conclusion of law 59 by replacing the word “faith” with “cause.” 8. Rate-Case Expenses The Commission severs rate-case expenses into a separate proceeding for further consideration of the reasonableness and necessity of the expenses. Accordingly, the Commission deletes findings of fact 210-216, modifies finding of fact 256, and deletes conclusion of law 58. D. Quality and Reliability of Service Issues 1. Reliability of Service The PFD in this case addressed certain overlapping issues related to American Electric Power Company's (AEP's) 49 petition to revise service-quality commitments in Docket No. 25157. 50 The PFD issued in Docket No. 25157 incorporated a portion of the PFD issued in this proceeding regarding service-quality issues and penalty payments. On December 17, 2004, TCC filed an alternative motion to sever and abate certain service-quality issues from this Docket No. 28840 to Docket No. 25157. TCC argued that the issues overlap and that severance promotes administrative efficiency and consistent treatment among all AEP companies. At its January 13, 2005 open meeting, the Commission granted TCC's motion. The Commission agrees that it is appropriate to consider all issues related to the service-quality commitments in a single proceeding, Docket No. 25157. Accordingly, the Commission does not adopt the ALJs' discussion of this issue in the PFD and deletes findings of fact 218 and 219 and conclusions of law 61 and 62. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 8 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... E. Rate Design 1. Load Data and Distribution Field Study The ALJs recommended that the load data and distribution field study provided by TCC be used in this proceeding. The ALJs also recommended that TCC develop new load data prior to TCC's next rate case. The Commission adopts these recommendations. In addition, the Commission requires TCC to develop a new distribution field study prior to its next rate case. Developing new data will ensure that TCC has the most recent information to determine costs in future ratemaking proceedings. 2. Energy-Efficiency-Program Costs The ALJs recommended that energy-efficiency-program costs be allocated on a 50% demand and 50% energy basis. The Commission reverses this recommendation based on PURA § 39.905(c), which specifically refers to energy demand when requiring “incentives sufficient for retail electric providers and competitive energy service providers to acquire additional cost- effective-energy efficiency equivalent to at least 10 percent of the electric utility's growth in demand.” Based on the language of the statute, the Commission finds that cost allocation should be made on a demand basis, rather than allocated on the basis of 50% demand and 50% energy. Therefore, the Commission modifies finding of fact 237 and conclusion of law 64 to allocate energy-efficiency costs based on a demand basis. 3. Debt-Reacquisition Costs The ALJs recommended disallowing the recovery of $12.5 million in debt-reacquisition costs. Due to this disallowance, the ALJs did not reach a decision on the proper allocation of these costs. However, as discussed in section II.C.2 of this Order, the Commission reversed the ALJs' recommendation and allowed for the recovery of the debt-reacquisition costs based on the stipulation and order in Docket No. 22352 in this proceeding. Consistent with this decision, the Commission adopts TCC's proposed allocation method for the recovery of these costs using a distribution-plant allocator. Before declining to issue a recommendation, even the ALJs pointed out that “the costs in question were incurred to finance invested capital, [and] it would appear that the refinancing costs should be allocated on the same basis as the underlying investments supported by the debt.” 51 The Commission agrees. Using the distribution-plant allocator will recover the costs from customers that primarily benefit from the investment supported by the debt. Accordingly, the Commission adds finding of fact 237A to reflect the proper allocation of the debt-reacquisition costs. 4. FERC Account 370 (Meter Installation) TCC proposed to allocate meter costs in FERC Account 370 to all customers based on a weighted number of meters for each class. TCC used the meter costs developed in Docket No. 28559, 52 the competitive-metering-credit docket, for all classes except for primary- and transmission-voltage-level customers. The costs for these customers were not updated in Docket No. 28559, and the costs used were from TCC's UCOS case, Docket No. 22352. Several parties objected to mixing cost data from two different time periods, arguing that it could lead to skewed and disparate results. The ALJ agreed, and recommended that the costs established in Docket No. 22352 be used for all classes. The Commission disagrees with the ALJs' recommendation, and finds that the use of the most up-to-date information is preferable. The data developed in Docket No. 28559 takes into account changes to the customer classes that have occurred since the UCOS docket. The Commission finds that TCC's proposed Account 370 allocator should be used to allocate meter costs, and appropriately modifies finding of fact 241. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 9 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 5. FERC Account 565 The ALJs recommended several changes proposed by Staff to TCC's Account 565 allocator. These changes to the allocator are due to TCC's incorrect methodology to develop the allocator. While the changes recommended by the ALJs ultimately achieve the correct results, the Commission clarifies that the correct method to determine the amount to be collected in retail rates for the transmission function is to use Schedule TCOS as included in the rate-filing package. Use of Schedule TCOS in future rate cases will achieve accurate results without the need for the corrections made by the ALJs. 6. Nuclear-Decommissioning Rider The ALJs recommended that nuclear-decommissioning costs should be recovered through base rates, pursuant to the settlement reached in Docket No. 22352. However, in the period since the ALJs issued the PFD, the Commission amended P.U.C. SUBST. R. 25.303(g)(1) to require that a utility's nuclear-decommissioning costs be “removed from its general rates and stated as a separate nonbypassable charge.” 53 Based on the change to Commission rules, the Commission reverses the PFD to require that nuclear decommissioning costs be recovered through a separate rider, and modifies findings of fact 259 and 261 and conclusion of law 71. 7. Resolved Disputes Several parties disputed different fees charged by TCC. Of these, the disputes were resolved between the parties relating to the Account History Fee, the Inaccessible Meter Fee, and the Service Call Fee. The Commission modifies the applicability of the Service Call Fee to clarify that the fee is only charged if, when a service call is made and an employee dispatched to the customer's premise, the source of the problem is on the customer's side of the meter. If the problem is determined to be on the company's side of the meter, the customer will not be charged for the Service Call Fee. Accordingly, the Commission modifies finding of fact 264 to give effect to this clarification. 8. Disputed Fees Several other fees that were disputed by the intervenors were not resolved. These fees are the Special Meter Reading Fee, Connect Fee, Service Reconnect Fee, Priority Connect Fee, Priority Disconnect Fee, Dispatched Order Fee, and the Priority Dispatched Order Fee. In the Remand PFD, the ALJs evaluated whether TCC provided sufficient evidence for the labor charges and the loading factor that were used to determine the rates for these services. TCC proposed a loading factor of 60.18%, which consisted of taxes and a non-productive fringe rate. The loading factor was multiplied by the hourly salary of the employee to determine the total-loaded-labor rate for each employee. The total-loaded-labor rate was multiplied by 2.5% to adjust for salary-grade-level increases from 2002 to 2003. TCC also determined the time that various employees performed for each task. The total-loaded-labor rate adjusted for the salary increase was multiplied by the amount of time for each employee for each service. This determined the cost for each employee involved for each service. The costs were added to determine the final cost and proposed charge for the service. The ALJs concluded that only 7.65% of the loading factor related to social security and medicare taxes was reasonable, and that no evidence was submitted showing that employees receive a salary increase of 2.5%. The ALJs, using the reduced loading factor of 7.65%, reduced the amount of all the disputed fees from what TCC recommended. The Commission notes that in the schedules provided, TCC proposes different charges based on the type of meter or equipment involved. For example, there are separate proposed charges for the Priority Disconnect Fee depending on whether there is a self- contained meter, a subsurface box, or pole/metering equipment. 54 In all three situations, the proposed charge is based on the amount of labor required for various employees, which use the total-loaded-labor rate with the salary adjustment. In the specific © 2015 Thomson Reuters. No claim to original U.S. Government Works. 10 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... situation of the Priority Disconnect Fee, only the charge related to the self-contained meter was disputed by intervenors and re-examined by the ALJs. The charges related to the subsurface box and the pole/metering equipment, which also include the loading factor and salary adjustment, were not disputed by the intervenors or the ALJs in the Remand PFD. This re-examination of all the other disputed fees was likewise limited to only a single type of charge within each fee category. Therefore, to ensure consistency in the use of the loading factor and the salary adjustment across the agreed and disputed items, the Commission finds that TCC's proposed fees should be adopted. The intervenors do not dispute using the loading factor and salary adjustment for some charges within each disputed fee category. It is inconsistent that the loading factor and salary adjustment be changed for certain charges and not for others within the fee categories. The Commission concludes that the loading rate and salary adjustment are appropriate, and should be used consistently for all service fees. Accordingly, the Commission modifies findings of fact R19-R22, and deletes findings of fact R23, R24, and 269. 9. Gradualism TIEC, the State, and CCR recommended that gradualism be applied in this case, while TCC and TXU rejected its application. TCC contended that this case is a better proceeding to benchmark T&D rates than the UCOS case, while TXU looked at the UCOS proceeding for Commission direction that gradualism is no longer appropriate. The State proposed gradualism on a function-by-function basis, which TIEC opposed. TIEC recommended that a cap of 1.75 times the system average be applied to the tariffed class as a whole. The State recommended a cap of three times the system average for the distribution function, and 1.5 times the system average for an increase to the metering function. The ALJs were not convinced that gradualism is an abandoned policy, but viewed the 1.75 times the system-average cap as inadequate, and stated that a cap of two times the system average is appropriate. The Commission declines to apply 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. Therefore, gradualism will not be used in this case, and the Commission modifies findings of fact 279 and 283, and deletes finding of fact 281. F. Miscellaneous Issues Finding of fact 224 is modified to delete the term “not” to reflect that customers were placed in the new classes in January 2002. 55 Finding of fact R17 is modified to remove “accumulated” and add “expense” as it relates to TCC's end-of-test-year depreciation expense. Additionally, findings of fact 48, 55, 158G, 272, R17, and conclusions of law 25A and 51 are modified to reflect updated numbers. 56 Conclusion of law 11 is modified to replace the term “data” with “rate base.” Additionally, conclusions of law 45-47 and 49 relate to inclusions of certain costs in rate base. The Commission modifies these conclusions to replace the term “rate base” with “cost of service.” Finally, the Commission adds findings of fact 206A-B to reflect the additional findings related to nuclear decommissioning expense requested by TCC. 57 III. Findings of Fact 1. AEP Texas Central Company (TCC, the Company, or the Applicant) is an electric utility operating company and wholly owned subsidiary of American Electric Power Company (AEP), a public utility holding company. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 11 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 2. TCC is a transmission and distribution (T&D) utility providing service to a 44,000 square-mile area of South Texas that includes the portion of Texas from just south of San Antonio to the Mexican border and from Bay City west to Eagle Pass. 3. TCC provides distribution service to approximately 785,000 electric connections receiving electric service from 28 retail electric providers (REPs) and provides wholesale and transmission service in the Electric Reliability Council of Texas (ERCOT). 4. On November 3, 2003, TCC filed an application with the Public Utility Commission of Texas to change its T&D rates. 5. On November 4, 2003, the Commission referred this case to the State Office of Administrative Hearings. 6. The Commission issued its Preliminary Order on December 5, 2003. 7. Concurrent with its filing of the application with the Commission, TCC filed a similar petition and statement of intent with each incorporated city in its service area that has original jurisdiction over its retail rates. Eighty-six (86) cities denied TCC's petition and statement of intent. TCC filed petitions for Commission review of those denials and filed motions to consolidate those petitions for review into this rate proceeding. 8. Notice of TCC's application was published once a week for four consecutive weeks in newspapers having general circulation in each county in TCC's service territory and was completed on November 30, 2003. 9. Individual notice of the application was provided on November 3, 2003, to the Commission Staff (Staff), Office of Public Utility Counsel (OPC), City of McAllen, City of Harlingen, City of Laredo, City of Victoria, City of Corpus Christi, and City of Edna. 10. Individual notice of the application was provided by November 3, 2003, to each municipality having original jurisdiction over TCC's rates. 11. Individual notice of the application was provided by November 3, 2003, to all retail electric providers who have been certified by the Commission. 12. Individual notice of the Application was provided to each party that participated in Application of Central Power and Light Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule § 25.344, Docket No. 22352 (Oct. 5, 2001), TCC's unbundled-cost-of-service (UCOS) rate case. 13. Individual notice of the application was provided on November 3, 2003 to each party that participated in Joint Application of AEP Texas Central Texas Company and LCRA Transmission Services Corporation to Transfer Certificate Rights and for Approval of Transfer of Facilities in Goliad and Karnes Counties, Docket No. 27282 (Oct. 31, 2003). 14. The following parties intervened and participated in the hearing: the Cities of Alice, Aransas Pass, Carrizo Springs, Dilley, Donna, Eagle Lake, Freer, Ganado, George West, Ingleside, Kingsville, La Feria, Laguna Vista, La Joya, Leakey, Los Fresnos, Lyford, Lytle, McAllen, Mercedes, Mission, Nordheim, Odem, Pharr, Port Aransas, Portland, Port Lavaca, Poteet, Rancho Viejo, Refugio, Rio Hondo, Runge, San Benito, San Juan, Sinton, Uvalde, and Weslaco (Cities); Texas Industrial Energy Consumers (TIEC); CPL Retail Energy (CPL Retail); Coalition of Commercial Ratepayers (CCR); City of Garland; Alliance for Retail Markets (ARM); TXU Business Services (TXU); Texas Legal Services Center and Texas Ratepayers' Organization to Save Energy (TLSC/ROSE); South Texas Electric Cooperative, Inc. (STEC); State of Texas; OPC; and Staff. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 12 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 15. Applicant requests approval of a revenue requirement of $519.9 million, based on an historical test year of July 1, 2002, through June 30, 2003. Of that amount, $426.6 million is for providing retail T&D service (including the portion of the ERCOT- wide transmission costs) and $93.3 million for providing wholesale transmission service. 16. Applicant proposes an overall rate increase of 14.7% from its current rate levels: a 19% increase for distribution service and a 2.5% decrease for transmission service. 17. TCC also seeks a good-cause exception to P.U.C. SUBST. R. 25.342(f)(1)(D)(ii)(III), requesting to share equally with the ratepayers all net revenues from transmission projects involving Magic Valley Electric Cooperative, Inc. (Magic Valley), Sharyland Utilities (Sharyland), and LCRA Transmission Services Corporation (LCRA). 18. TCC also seeks approval of a modification of its business separation plan (BSP). The change would allow TCC to retain its generating assets as part of TCC instead of creating a new unregulated subsidiary for those assets, until they are sold to a third party. 19. The hearing on the merits was held from March 2 through March 18, 2004. The record closed on June 17, 2004. 20. TCC proposed an effective date of December 8, 2003, for the proposed rates. The effective date was suspended for 150 days until May 7, 2004, pursuant to P.U.C. PROC. R. 22.33(b)(6) and P.U.C. SUBST. R 25.241(i). In a letter dated May 13, 2004, TCC agreed to extend the effective date for new rates until August 6, 2004. At the Commission's January 13, 2005 open meeting, TCC agreed to waive the effective date to allow the Commission additional time to complete the processing of this case. R1. The Commission issued Orders on July 28 and August 25, 2004, remanding portions of the case to the State Office of Administrative Hearings. R2. A hearing on the remanded consolidated tax savings issues was held on September 3, 2004. The record closed on September 17, 2004. 20A. On March 3, 4, and 7, 2005, the Commission held additional hearings to further analyze the evidence previously filed regarding merger savings, affiliate expenses, and distribution administrative and general expense. A. Merger Savings and Expenses 21. In Application of Central and South West Corporation and American Electric Power Company, Inc. Regarding Proposed Business Combination, Docket No. 19265 (Nov. 18, 1999), the Commission approved an Integrated Stipulation and Agreement (ISA) between the Applicant and many of the intervenors in this case, including Cities. 22. The parties' agreements in the ISA define some of the rights and obligations of the parties in this application. 23. In June and July 2003, the cities of McAllen, Victoria, Laredo, Corpus Christi, Harlingen, and Edna (Six Cities) adopted resolutions that constituted notice of each city's intent to proceed with an inquiry into the T&D rates charged by the Applicant. 24. The goal of each city's inquiry was to determine whether the rates being charged by the Applicant were just and reasonable. 25. The resolutions provided that a procedural schedule should be established for the filing of a rate package by the Applicant, concluding with a public hearing. 26. On July 14, 2003, before any of the Six Cities' proceedings were initiated, the Six Cities entered into a Stipulation and Agreement (July 14 Agreement) with the Applicant. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 13 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 27. The purpose of the July 14 Agreement was to alter the terms of their resolutions by providing that: (a) the Applicant would file a rate filing package with each of the cities by November 3, 2003, in the form required by the Commission, (b) the cities would schedule a public hearing at a date to be set later, and (c) the Applicant would file its rate filing package with the Commission on November 3, 2003, “in order to initiate the [Commission's] review of [the Applicant's] rates.” 28. The Six Cities gave notice that each would inquire into the question of whether the Applicant's rates were just and reasonable. 29. The ISA contains a set of contingent agreements that turn upon the issue of whether the Applicant “initiates” a rate case prior to the expiration of a six-year period from the approval of the ISA. 30. The Six Cities' actions in giving notice of their intention to inquire into the reasonableness of the Applicant's rates, without a final determination, cannot reasonably be characterized as the cities' having initiated a rate case with the Commission. 31. The Applicant initiated the rate case with the Commission. 32. Section 3.F.(3) of the ISA provides that, in cases initiated by TCC, merger-savings expenses and costs to achieve merger savings will not be allowed in the cost of service unless TCC demonstrates that the proposed rate increase results from circumstances not directly or indirectly related to the merger and that the full level of achieved merger savings for the applicable year have been achieved. 32A. Attachment D of the ISA requires TCC to demonstrate that it achieved $22,513,700 in merger savings during the year applicable to this proceeding. 32B. TCC demonstrated that it achieved at least $27 million in merger savings, therefore meeting the full level of savings required by Attachment D. 33. Section 3.F.(2) of the ISA permitted TCC to defer and amortize its costs to achieve the merger over a six-year period following the effective date of the merger. 34. Section § 3.F.(3)(b) of the ISA provides that the revenue requirement otherwise found reasonable and necessary will be reduced by the annual amount included in Attachment E of the ISA if TCC files a proceeding to increase rates that are to be in effect prior to the end of the six-year period after the effective date of the merger. 35. The merger became effective on June 15, 2000. 36. Because the test year for this case ended on June 30, 2003, the revenue requirement otherwise found reasonable and necessary should be reduced by $7,496,000, as provided for in Attachment E. B. Rate Base Adjustments 37. TCC's proposal to reclassify $24.7 million (distribution) and $18.2 million (transmission) in plant-related investment from construction work in progress to plant in service is uncontested and is reasonable. 38. TCC proposes a post-test-year adjustment that would increase rate base by $8,228,567 for distribution-plant expenditures made during the test year for capital projects that were added to plant in service before the new rates are to take effect. 39. The $8,228,567 of distribution plant was dedicated to and in public service before the rates set by this order will take effect. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 14 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 39A. P.U.C. SUBST. R. 25.231(c)(2)(F)(i)(II) requires any post-test-year addition to constitute at least 10% of the utility's requested rate base, whereas P.U.C. SUBST. R. 25.231(c)(2)(F)(iii) contains no such requirement for a rate-base reduction. 40. TCC's rate base is $1,343,448,441. TCC's proposed post-test-year adjustment of $8,228,567 does not comprise at least 10% of its requested rate base. 41. TCC did not make any adjustments to revenues resulting from customer growth between the end of the test year and the in-service date of TCC's plant additions. 42. TCC failed to account for accumulated depreciation and accumulated deferred income tax associated with the plant additions. 43. TCC's proposed adjustment to increase rate base by $8,228,567 is unreasonable. 44. TCC's proposal to make a post-test-year reduction to rate base, reflecting its plan to sell $6.2 million worth of distribution facilities to industrial customers, is uncontested and is reasonable. 45. It is reasonable to reduce TCC's material and supplies inventory from $13,805,198 to $13,503,928 based on more recent data. 46. TCC redesigned improvements to the Coleto Creek substation to accommodate ERCOT's plans for future transmission lines that would connect to the substation. The cost of the redesigned improvements was $3,016,482. 46A. TCC prudently re-examined and altered its design plans to accommodate ERCOT's proposal of a Coleto-to-Cuero-to- Holman double-circuit-capable 345-kV line. 47. Only $180,000 of the redesigned improvements to Coleto Creek are not useful to TCC in serving its current ratepayers. 47A. It is reasonable to include in TCC's rate base $2,836,482 in improvements resulting from the redesign of the Coleto Creek substation. 48. TCC's proposal to include a cash-working-capital amount in rate base of $6,672,117 for distribution and ($2,209,787) for transmission is reasonable and appropriate. 49. TCC's lead-lag study is reliable and fully supports TCC's cash-working-capital proposal. 50. Factoring of accounts receivable should be considered because it historically benefits customers. 51. TCC is unable to factor any of its REP accounts receivable at this time, because the banks with which it dealt previously are no longer willing to factor TCC's receivables. 52. At this time, TCC is not able to factor its accounts receivables to the same extent and under the same terms that its predecessor was able to factor wholesale accounts receivables in the past. Changed circumstances in the future, however, may make such an adjustment appropriate in a subsequent rate case. 53. Deleted. 54. As required by the Commission's rate-filing package, TCC functionalized its costs by assigning them to the various functions TCC performs, such as transmission, distribution and T&D customer service. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 15 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 55. FERC Account 907 includes customer service and information expenses. It is appropriate to functionalize $53,490 of TCC's test-year Account 907 costs to the T&D customer-service function rather than demand-side management (DSM) because they were directly related to the supervision of customer-service activities. 56. FERC Account 303 is entitled Miscellaneous Intangible Plant. It is appropriate to disallow $916,000 in this account for a software package because it relates to marketing in which a T&D utility like TCC need not engage. 57. FERC Account 303 also includes three software programs related to customer information and billing services (with a cost of $9,510,439). TCC incorrectly assigned them to the distribution function, and they should instead be assigned to the T&D customer-service function. 58. FERC Account 303 also contains the cost of several software programs used for plant accounting: the Tax Depreciation & Normalization System, the General Ledger/Standard Account Structure System, and the Job Cost Accounting and Material Management System. These accounting-related programs and costs should not be functionalized based on the amount of plant investment by function. Instead, they should be directly assigned or functionalized using the number of accounting entries by function because this method best represents the costs each function imposes on these accounting systems. C. Return on Equity and Capital Structure 59. On April 30, 2004, TCC, TIEC, CPL, and Staff filed a non-unanimous stipulation (Return Stipulation) that settled two main issues: return on equity (ROE) and capital structure. 60. The terms of the Return Stipulation are that: TCC's ROE be set at 10.125%; its capital structure be set at 60% debt and 40% equity; its rate of return on invested capital be set at 7.475%; and no penalty be applied to TCC's ROE for quality or reliability of service. 61. The parties expressing neither opposition nor support for the Stipulation are OPC, the State, TLSC/TexasROSE, ARM, Brazos, STEC, Garland, TXU, and Occidental Power Marketing, LP. 62. Cities and CCR object to the Return Stipulation. 63. The range of the ROE recommendations of the various expert witnesses in this case are as follows: Witness Range Mr. Stephen Hill 9.00% to 9.75% Dr. Carol Szerszen 9.2% to 10.0% Mr. Michael Gorman 9.2% to 10.5% Dr. Charles Smaistrla 10.00% to 10.25% Mr. Slade Cutter 9.22% to 10.23% Mr. Paul Moul No range (12.000%) 64. The quality of TCC's service is generally adequate and does not warrant a reduction is TCC's ROE. 65. The stipulated return of 10.125% is more likely than not a reasonable return on TCC's equity. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 16 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... D. Affiliate Costs 66. TCC is a wholly owned subsidiary of AEP. 67. AEP Service Company (AEPSC), a wholly owned subsidiary of AEP, is a service company that provides a wide variety of operations and support services to TCC. These services include transmission, distribution, customer services, supply- chain shared services, general services, information technology, telecommunications, human resources, corporate relations, regulatory, legal and public policy, customer-choice operations, financial services, interest and amortization, internal support, research and development, risk management, treasury, cash management and investor relations. 68. During the test year, TCC engaged in transactions with AEPSC and other AEP affiliates. 69. AEP uses AEPSC and other affiliates to provide most of the personnel and services to the Applicant so that the Applicant can serve its customers. 69A. The services provided to TCC by other affiliates consist of service payments, where the affiliate provides a service (such as transmission) or convenience payments where the affiliate receives an invoice for costs shared by more than one entity and bills the other entity for its share. 70. Relatively few employees that provide services through the Applicant are TCC employees. 71. TCC seeks to include in its costs of service $60,362,087 in affiliate expenses provided to TCC by AEPSC and $3,429,479 in affiliate expenses provided by other AEP affiliates of TCC, for a total of $63,791,566 in requested affiliate expenses for the test year. 72. TCC has not presented evidence of either the amounts of increases actually requested for affiliate expenses or the level of affiliate expenses currently included in the rates pursuant to the “black box” settlement of the UCOS case (Docket No. 22352). Thus, the Commission is presented with only two sets of data: the level of affiliate expenses TCC requests in this case and the amount requested in the UCOS case. R9-R13. Deleted. 73-158. Withdrawn by ALJ in Remand PFD. 158A. On June 6, 2005, TCC and TIEC filed a joint motion to implement a non-unanimous stipulation (NUS) regarding affiliate expenses. 158B. The parties expressing no opposition for the NUS are: Staff, Cities, Coalition of Commercial Ratepayers, Brazos Electric Power Cooperative, Inc., Occidental Chemical, South Texas Electric Cooperative, Inc., the City of Garland, Alliance for Retail Markets, and TXU Business Services. 158C. The State of Texas takes no position on the NUS. 158D. The NUS is opposed by OPC, TLSC/Texas ROSE, and CPL Retail Energy. These parties did not request a hearing on the NUS. 158E. The NUS proposed a disallowance of $10,501,860 in AEPSC expenses. The stipulated disallowance consists of $1,116,742 in AEPSC expenses that TCC previously agreed it would no longer seek recovery of, $5,496,028 of expenses in © 2015 Thomson Reuters. No claim to original U.S. Government Works. 17 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... the AEPSC customer service support class of affiliate expenses, and $3,889,090 in the AEPSC distribution class of affiliate expenses. 158F. The NUS proposes to allocate the stipulated disallowance as follows: $10,300,935 to the distribution function and $200,925 to the transmission function. 158G. The stipulating parties agree that the remaining $53,289,706 in affiliate expenses, which consist of $49,860,227 in affiliate expenses from AESPC and $3,429,479 in affiliate expenses from other affiliates, are reasonable and necessary, and that the price is not higher than the price charged by the supplying affiliate to its other affiliates or divisions or to nonaffiliated persons for the same item or class of items. 158H. The range of expert testimony regarding disallowances of affiliate costs are as follows: Cities $16.6 million OPC $13.4 million CPL Retail $10.3 million E. Debt Reacquisition Costs 159. TCC proposes to include in rate base $12,456,000 of restructuring costs related to debt refinancing. TCC also includes an amount equal to 1/15th of that total amount ($861,712) in TCC's operating expenses. TCC proposes a 15-year amortization for those costs. 160. The decision to reacquire the first mortgage bonds was driven by unbundling. 161. Deleted. 162. The debt reacquisition costs should be included in rate base and amortized over fifteen years, as required by Docket No. 22352, CPL's UCOS case. F. Salary Adjustments and Related Taxes 163. Of the $679,344 in salary adjustments and related taxes proposed by the Applicant, $508,761 was proposed for post-test- year raises for staff. G. Incentive Compensation 164. The compensation packages that the Company offers its employees include a base payroll amount as well as an incentive- compensation portion. Both portions are part of an overall compensation package that is designed to be competitive in the marketplace and allow the Company to attract and retain qualified individuals as employees. 165. The Company requests to include the test-year level of incentive-compensation expense of $4,422,937 in cost of service. 166. The Company's incentives are set through two types of performance measures, financial and operational. 167. Thirty-four percent of the incentive-compensation expenses are for operational measures. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 18 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 168. To the extent that the Applicant's employees are given an incentive, their rewards are made with respect to the overall performance of the holding company. 169. The financial measures are of more immediate benefit to shareholders, and the operating measures are of more immediate benefit to ratepayers. 170. Incentives to achieve operational measures are necessary and reasonable to provide T&D utility services, but those to achieve financial measures are not. H. Pension Expense 171. The Company proposes to increase test-year pension expenses by $7,264,784 from $30,812. 172. The Company's proposed adjustment to the test-year amount of pension expenses is based on forecasts that are highly dependent on changes in stock-market prices and market interest rates. 173. Future stock-market prices and market interest prices are not within the category of known and measurable changes. I. Other-Post-Employment-Benefits 174. TCC requests approval of increased revenues to support an other-post-employment-benefits (OPEB) expense of $5,239,235. 175. OPEB expenses in cost-of-service calculations are subject to P.U.C. SUBST. R. 25.231(b)(1)(H), which requires OPEB expenses to be based on “actual payments made.” 176. The proposed OPEB expense item had been adjusted to reflect actuarial projections for the 2004-2005 rate year, an amount that had not been funded and that did not represent actual payments made. J. Group Insurance Expense 177. The Company's requested amount of group-insurance expense, $4,649,872, represents the actuarial estimate of the amount that the Company will contribute into its employee group insurance trust fund during the rate year. 178. The requested amount is comprised of the test-year actual cost of $3,741,039 and a projected increase of $908,833. 179. The Applicant's test-year group-insurance expense is reasonable and necessary. 179A. The Applicant's proposed post-test-year group-insurance expense is based on an actuarial study; therefore, this does not qualify as a known and measurable increase to a test-year expense. K. Catastrophe Reserve 180. The Applicant's proposed increase in its catastrophe-loss reserve from approximately $5.4 million to $13.5 million is based on a projected increase in storm damage. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 19 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 181. The current upper limit of $5,353,563 for the Catastrophic Reserve is not adequate to cover losses from hurricanes and other storms. 181A. TCC should fund the catastrophe reserve at $900,000 annually for 10 years as part of the rate-base expense until the catastrophe reserve reaches its maximum approved level of $9,000,000. L. DSM Costs 182. The Applicant's test-year energy-efficiency costs were $6,082,450, which should be included in cost of service. M. Gain on Sale of the AREP 183. When customer choice began in Texas on January 1, 2002, AEP formed a subsidiary, Mutual Energy CPL L.P, to be the affiliated retail electric provider (AREP), and the former Central Power and Light Co. became TCC. 184. On December 23, 2002, AEP sold the AREP to Centrica. 185. The sale involved the sale of retail assets and not transmission or distribution assets. 186. AEP's gain on the sale of the AREP should not be used to reduce TCC's T&D rates. N. Bad-Debt Expense 187. The Applicant proposes to create a deferral account in which the Applicant would accrue bad debt arising from future REP bankruptcies. The Applicant would use the deferral account in which to record any bad debt as a regulatory asset. 188. No current provision of law would permit recovery of bad debts through the proposed method. O. Ad Valorem Taxes 189. TCC's test-year ad valorem tax expense was $18.3 million. 190. The Company's request to increase its ad valorem tax expense included in its cost of service by $2.5 million is reasonable. 191. This amount was calculated by applying the effective ad valorem tax rate during the test year to the Company's end-of- test-year property balances. P. Consolidated Income Taxes 192. TCC is a member of an affiliated group eligible to file a consolidated tax return. 193. AEP files annual consolidated federal income tax returns on behalf of itself and its various subsidiaries. 194. A consolidated tax savings adjustment should be made based on the value of the tax shield the utility provides to the parent company and its nonregulated affiliates. 195. Withdrawn by ALJ in Remand PFD. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 20 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 196. Withdrawn by ALJ in Remand PFD. R3. It is reasonable to use the interest-credit methodology to calculate TCC's consolidated federal-income-tax-savings adjustment. R4. An additional adjustment should be made to reflect the savings due to generation assets that are no longer part of the transmission and distribution (T&D) utility. R5. Using the rate-base percentage assigned to the T&D functions in effect for each of the 15 years prior to 2002 is an appropriate method for functionally assigning consolidated tax savings. R6. The percentages of the T&D functions for each of the 15 years prior to 2002 produces an allocation of 23.1% to T&D, resulting in an adjustment of $1,509,656. R7. Because the adjustment is a direct adjustment to federal income taxes, it must be grossed up to reflect the full effect on revenue requirement of the adjustment. R8. The combined effect of the consolidated tax-savings adjustment and the associated gross-up is 1.53846 times the $1,509,656 adjustment for an amount of $2,322,545 to be deducted from federal-income-tax expense. Q. Distribution Operations & Maintenance (O&M) Expense Adjustments 197. When Customer Choice went into effect and costs were functionalized, TCC included three adjustments that it seeks to include in its cost of service. 198. The $1.5 million adjustment to correct a mis-entry and the $1.6 million adjustment to correct a building-service posting should be included in TCC's cost of T&D service. 199. The third adjustment of $3.4 million to reflect changed salvage value for vehicles is only supported to the extent of $2.4 million, which lower amount should be included in TCC's cost of service. 200. Of the $2.4 million adjusted amount sought by the Applicant for this expense, $1.0 million of the decreases were attributed “to various other distribution O&M accounts.” 201. The evidence shows that $1.0 million represents vehicle maintenance expense, a cost of TCC's service. R. Distribution Accounting and General (A&G) Expense Adjustments 202. The Applicant's $58.0 million proposed distribution A&G expenses are reasonable and a necessary cost of TCC's T&D service. R14. The A&G Expense associated with the distribution function is $58,012,772, including twenty categories of adjustments. R15. TCC's evidence supports the foregoing proposed A&G expenses, including the adjustments, as just and reasonable, with two exceptions. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 21 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... R16. The two exceptions are Adjustment No. 1, the pension-expense increase of $6,258,658, and Adjustment No. 16, the merger-related revenue requirement-credit of $7,496,000. S. Depreciation Expense 203. Withdrawn by ALJ in Remand PFD. R17. TCC's adjusted end-of-test-year depreciation expense was $64,488,771. R18. TCC has agreed to and will establish a depreciation reserve by plant account and maintain the reserve by plant account. T. Decommissioning Expense 204. TCC's share of the cost to decommission the South Texas Project (STP) will be recovered with an annual contribution of $7.58 million from TCC, which should be included in TCC's cost of service. 205. This amount includes the 10% contingency factor included in the Commission's decommissioning rule. 206. TCC's request to include an additional $580,000 in its cost of service for STP decommissioning for a total of $8.16 million should be denied. 206A. The amount of decommissioning costs included in the cost of service for Units 1 and 2 of the South Texas Project is $3,726,662 and $3,856,079, respectively, for the Texas jurisdiction. 206B. The assumptions used in determining the amount of decommissioning costs included in the cost of service for Units 1 and 2 are as follows: a. The after-tax rates of return assumed to be earned by the amounts collected for decommissioning are shown in the following table: Unit 1 Unit 2 Years Rate of Return Years Rate of Return 2003-2025 6.282% 2003-2027 6.282% 2026-2031 4.713% 2028-2045 4.713% 2032-2035 2.977% 2046-2046 2.977% 2036-2037 2.283% 2047-2048 2.283% b. The after-tax rates of return assumed to be earned by the decommissioning funds were calculated using the 20% tax rate applicable to qualified decommissioning funds. c. The proposed method of decommissioning for Units 1 and 2 is DECON as defined by the Nuclear Regulatory Commission (NRC). © 2015 Thomson Reuters. No claim to original U.S. Government Works. 22 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... d. The total estimated cost of decommissioning Units 1 and 2 in 1998 dollars is $515.5 million for Unit 1 and $616.3 million for Unit 2. TCC's portion of those costs is $125,070,410 for Unit 1 and $150,611,711 for Unit 2. e. TCC's estimated cost of decommissioning for Units 1 and 2 in future dollars is $463,992,921 for Unit 1 and $633,771,877 for Unit 2. f. The escalation rates used to convert the current-dollars estimated decommissioning costs to future-dollars estimated decommissioning costs vary by year and average 4.2% until the time of the last projected payment for decommissioning. g. Decommissioning costs included in the cost of service total $7,582,741, as detailed in finding of fact 206A, above, commencing with the effective date of the rates authorized by this Order, until changed by a future order. For purposes of determining the amount of funds available for decommissioning each individual unit, collection of each individual unit's costs continues through the license expiration dates of each respective unit. h. The dates of NRC license expiration are August 20, 2027 for Unit 1 and December 15, 2028 for Unit 2. i. The amount of decommissioning costs included in TCC's cost of service is based upon the 1999 decommissioning study prepared by TLG. Services, Inc. U. Third Party Contract Margin Sharing Proposal 207. Through its associated business development (ABD) operations, the Applicant provides O&M services and major transmission construction services to third-party clients, which is an “other service” under P.U.C. Subst. R. 25.342(f)(1)(D). 208. The Applicant seeks a good-cause exception to the provisions of the “other services” rule, P.U.C. Subst. R. 25.342(f) (1)(D)(ii)(III), that requires all revenue from an “other service” to be credited so as to reduce a utility's cost of service. The exception would permit the Applicant to contribute half-instead of all-of the margins received as part of the Applicant's ABD program to the rate base calculation. 209. It is not reasonable to grant TCC's request and the full amount of ABD's test-year margins should be credited to TCC's cost of service, reducing TCC's proposal by $2.7 million. V. Rate-Case Expenses 210. Deleted. 211. Deleted. 212. Deleted. 213. Deleted. 214. Deleted. 215. Deleted. 216. Deleted. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 23 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... W. Miscellaneous Issues 217. At the time of this rate application, TCC was in the process of selling its generating assets. TCC's business separation plan required that the generating assets be transferred to an affiliate corporation. TCC's request to sell the generating assets directly rather than through an affiliate corporation is unopposed and is reasonable. X. Quality of Service 218. Deleted. Y. Reliability of Service 219. Deleted. Z. Rate Design 220. A cost-of-service study is used to allocate a utility's cost of service to its various customer classes based upon each class's cost responsibility and to determine each class's rates. 221. TCC's revenue requirement was attributed to the various classes by classifying each cost by function, including production (for nuclear decommissioning), transmission, distribution, customer service (including meter reading, billing and collection, and customer information) and administrative and general costs; classifying the costs of each as demand, energy, or customer costs; and by allocating those costs among the customer classes. AA. Load Data 222. TCC used ERCOT load-profile shapes and TCC actual consumption data to develop the demands used in its cost-of- service study. 223. The ERCOT load-profile shapes used by TCC are the load profiles used by ERCOT to settle the market in TCC's service area on a 15-minute-by-15-minute basis. 224. TCC did not have sufficient time to derive its own load data because the final order in its UCOS case was issued in April 2001 and customers were placed in their new classes in January 2002. 225. It takes 18 to 24 months to design load-research samples, select the samples, place recording meters in the field, and to collect and analyze the data. 226. In March 2002, the Commission initiated Project No. 25516, which concluded in March 2003, the purpose of which was to ascertain and allocate load-research responsibilities in the newly opened market. 227. TCC was not imprudent in failing to have its own post-choice research data available for use in its cost-of-service study. 228. The load data and methodology used by TCC were appropriate for use in its cost-of-service study. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 24 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... BB. Cost of Service Allocations 229. TCC relied on a July 31, 1999 study, which it used in its UCOS case, to determine the distribution-function cost of service in this proceeding. 230. The study categorizes costs as either customer or demand and separates demand-related plant between primary voltage and secondary voltage. 231. The cost of the distribution system, including poles, transformers, and conductors, does not generally vary. 232. TCC properly allocated the costs of the distribution function found in FERC Accounts 364, 365, 367, and 368. 233. In Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965, Second Order on Rehearing (Oct. 15, 1997), Central Power and Light Co.'s last rate case, the Commission approved the use of the probability of dispatch methodology to allocate costs. 234. In Docket No. 22352, TCC's UCOS case, nuclear-decommissioning costs were allocated based on a settled factor, the Joint Recommendation on Reserve Spread. 235. Nuclear-decommissioning costs are not stranded costs. 236. TCC properly allocated nuclear-decommissioning costs using an average and excess, four coincident peak (A&E/4CP) allocator because its use is consistent with Ordering Paragraph No. 12 in Docket No. 14965. 237. Energy-efficiency costs are appropriately allocated on the basis of demand. 237A. Debt-reacquisition costs are appropriately allocated on the basis of the plant-distribution allocator. 238. The non-DSM supervisory costs originally included in Account 907 (Supervision) are properly allocated on the basis of labor consistent with the allocation of other non-DSM supervisory costs. 239. TCC appropriately allocated the costs contained in Account 903 (Customer Billing and Record) using weightings because the time associated with billing IDR-metered customers substantially exceeds the time associated with billing non IDR-metered costs, thereby substantially increasing the costs associated with billing IDR-metered customers. 240. The Company has provided sufficient justification of its current installed meter costs as the basis for determining the allocation of meter costs among customer classes. 241. TCC appropriately developed the Account 370 cost allocator using information on meter costs from the competitive metering-credit-docket and information on the primary and transmission classes from TCC's UCOS docket that was not included in the competitive-metering-credit docket. 242. TCC should use $0.935 per kW as the Access Fee for City Public Service of San Antonio (CPS) because $0.935 per kW is the current approved rate. Because CPS' application to change its wholesale access fee has been resolved, TCC may adjust its retail rates through the transmission cost recovery factor mechanism. 243. TCC unnecessarily adjusted the 4CP allocator used in allocating the ERCOT TCOS revenue requirement; the unadjusted 4CP allocator should be used. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 25 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 244. The allocation of individual expense adjustments should be made based on the original allocation that TCC has used or each expense in the cost of service models. On page 12 of 14 in TCC's schedule II-I-I, the $1,868,116 (costs associated with catastrophic reserve) and $1,330,334 (costs associated with rate-case expenses) are recorded on two lines and are allocated to different functions based on different allocations. To correctly reduce these expenses in the cost-of-service model, these expenses should be adjusted differently, based on their original allocations, and not based on a composite allocator. 245. An adjustment of $2,610 related to depreciation expense associated with the $180,000 plant adjustment for the Coleto Creek substation investment should be made in Account 353 (Station) where the $180,000 adjustment is made. 246. TCC has corrected the error concerning the Taxable Income Allocator. 247. The accounting schedules do not reflect functionalization changes resulting from the cost-of-service functionalization. TCC's cost-of-service study more accurately reflects the functionalized costs. 248. The allocation factors that are used to allocate certain distribution costs and are derived from costs included in a number of FERC accounts including FERC Account 565 should be corrected to exclude the costs (the ERCOT TCOS revenue requirement) included in FERC Account 565. The ERCOT TCOS revenue requirement is not part of the distribution costs and should not be included in the development of the allocators used for allocating distribution costs. 249. Allocation Factors Nos. 57, 68, and 103 as corrected by Staff should be used in determining class revenue allocations. CC. Municipal-Franchise Fees 250. Municipalities charge utilities franchise fees for the use of their streets, alleys, rights-of-way, and other property, which benefits all ratepayers. 251. TCC's proposal to allocate municipal fees to all customers is not appropriate. The cost of municipal-franchise fees should be directly allocated to customer classes based upon the number of kWh delivered within the municipal boundaries. 252. TCC's proposal to collect the cost of municipal-franchise fees from all classes in TCC's system under a spread-collection method is appropriate. 253. Municipal franchise fees should be collected through base rates and not through a separate rider. 254. TCC's proposal to implement the Municipal Franchise Fee Adjustment Rider should be rejected as it would create confusion with potentially over 100 different rates resulting. 255. Simple rates and uniform customer classifications promote competition. Having different rates in each of the municipalities in TCC's service territory is contrary to the Commission's desire for uniform, simple rates. DD. Rate-Case Expenses 256. It is appropriate to surcharge all rate-case expenses to be collected from all customers over three years. EE. Riders © 2015 Thomson Reuters. No claim to original U.S. Government Works. 26 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 257. A utility cannot increase its rates unless it demonstrates that its total revenues are insufficient to recover the totality of its costs, plus a reasonable rate of return. Singling out certain expenses in order to guarantee dollar-for-dollar cost recovery is piecemeal ratemaking. 258. TCC's proposed energy-efficiency cost-recovery rider with its three-year true-up provision lacks merit because it could lead to inflated rates and discourage cost control. 259. The proposed nuclear decommissioning rider (NDC Rider) should be accepted based on P.U.C. SUBST. R. 25.303. 260. CPL Retail's proposed rider for catastrophe reserve is unnecessary. 261. All of the riders requested by TCC and CPL Retail, except for the NDC Rider, should be denied to avoid over-recovery and piecemeal ratemaking. The costs associated with the proposed riders can be adequately recovered through base rates. FF. Discretionary Service Charges 262. The Account History Fee was erroneously included in Schedule IV-J-2 and should not be approved. 263. The proposed inaccessible Meter Fee, along with its associated revenue credit of $1,229,223, should be removed from discretionary services. 264. The tariff language of the Service Call Fee should be modified to clarify that customers will not be assessed the fee when the customer perceives a safety hazard or if the problem addressed is TCC's responsibility. 265. The Copy Fee and Special Products/Service Fee is not a substitute for the Account History Fee and is being appropriately billed to those who require the service. 266. Withdrawn by ALJ in Remand PFD. 267. Withdrawn by ALJ in Remand PFD. 268. Withdrawn by ALJ in Remand PFD. R19. TCC provided sufficient evidence for its loading factor of 60.18%. R20. TCC provided sufficient evidence for its supervisor labor charges. R21. TCC provided sufficient evidence showing that the employees in questions will receive a salary increase of 2.5%. R22. The amounts for the Connect Fee, Service Reconnection Fee, Meter Reading Fee, Priority Connect Fee, Priority Disconnect Fee, Dispatched Order Fee, and the Priority Dispatched Order Fee are reasonable at the levels proposed by TCC. R23. Deleted. R24. Deleted. 269. Deleted. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 27 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... GG. Lighting 270. TCC's lighting charges result in a double-recovery of lighting maintenance expense. The bulb-replacement portion should be removed from the maintenance component of the fixed-charge rate calculation for lighting. 271. The cost-of-capital component of the fixed-rate charge calculation should be adjusted to reflect the cost of capital found reasonable by the Commission in this proceeding. 272. TCC understated non-roadway lighting-facilities revenue by $298,677 when it left out revenue from the 175-Watt mercury- vapor fixture type. This amount should be credited to lighting customers. 273. Lighting service is not metered and when a bulb goes out, TCC has charged lighting customers for service that is not provided. 274. In the settlement of Docket No. 22352, TCC agreed to continue to provide non-roadway lighting service. In section 7(A) (2) of the ISA, TCC agreed to replace 95% of burned-out security and street lighting bulbs within 72 hours. 275. TCC's proposed a tariff change to allow five days for replacement of streetlights and fifteen days for non-roadway lighting is inconsistent with section 7(A)(2) of the ISA standard agreed to by TCC and should be rejected. 276. TCC's use of average dusk-to-dawn burn time to estimate usage takes into consideration abnormalities associated with lighting KWh usage. 277. TCC's tariffs should be amended to state that a credit will be provided to the customer if TCC fails to restore a bulb within three working days after official notice of the outage from the customer to ensure that lighting customers are not charged for service when the bulbs are burned out. HH. Revenue Allocations 278. TCC's proposed allocation of $4,520,746 for Other Revenue should not be adopted. The revenue should be allocated in the same manner that TCC allocates its investment in poles, towers, and fixtures, because the method more closely tracks the method used to allocate the underlying investment used to generate the revenue. II. Gradualism 279. In prior rate cases the Commission has moderated the impact of new rates with gradualism to avoid rate shock 280. Gradualism is not an abandoned policy. 281. Deleted. 282. A gradualism constraint should be applied to the total system revenue requirement, not on a function-by-function basis. 283. If TCC's rates are changed, then the T&D rates charged to each customer class should move to cost of service. Therefore, the Commission declines to adopt gradualism in this case. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 28 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... IV. Conclusions of Law 1. TCC is an electric utility as defined by § 31.002 of the Public Utility Regulatory Act (PURA), TEX. UTIL. CODE ANN., and therefore it is subject to the Commission's jurisdiction under §§ 32.001, 33.051, and 36.102. 2. TCC is a T&D utility as defined in PURA § 31.002(19). 3. SOAH has jurisdiction over all matters relating to the conduct of the hearing in this case, including the preparation of a Proposal for Decision pursuant to PURA § 14.053 and TEX. GOV'T CODE ANN. § 2003.049(b). 4. Each municipality in TCC's service area that has not ceded jurisdiction to the Commission has jurisdiction over the application to the extent that the application seeks to change rates for distribution services within each municipality pursuant to PURA § 33.001. 5. TCC provided adequate notice of this proceeding in compliance with P.U.C. PROC. R. 22.55. 6. The effective date of any change approved in this case was extended pursuant to P.U.C. PROC. R. 22.33(c), with the agreement of applicant, and P.U.C. SUBST. R. 25.241(i). 7. TCC met its burden of proof with regard to sections 3.F.(3)(a)(ii) of the ISA, and TCC's proposal to increase rates by $22,513,000 for merger expenses is approved. 8. The revenue-requirement credit applies since the Applicant initiated the filing of the rate case. 9. The revenue-requirement credit is determined by a simple counting of each of the years in the six-year period after the effective date of the merger. 10. The revenue-requirement credit is the amount listed in Year 3 of Attachment E of the ISA, $7,496,000. 11. TCC's proposed addition to historical test-year rate base does not comprise at least 10% of its requested rate base, as required by P.U.C. SUBST. R. 25.231(c)(2)(F)(i)(II) for a post-test-year adjustment. 12. TCC failed to appropriately take into account all of the attendant impacts associated with plant in service, as required by P.U.C. SUBST. R. 25.231(c)(2)(F)(i)(IV) for a post-test-year adjustment, including adjustments to revenues resulting from customer growth beyond the end of the test year and accumulated depreciation and accumulated deferred income tax associated with the plant additions. 13. The design changes to Coleto Creek substation in the amount of $2,836,482 should be included in TCC's rate base because the improvements benefit the ratepayers and are used to serve the ratepayers as P.U.C. SUBST. R. 25.231(c)(2)(F) requires for a post-test-year adjustment. 13A. Electric utilities should be encouraged to cooperate with ERCOT and make reasonable modifications to Commission- approved plans for facility construction when doing so would avoid costly facility duplication in the foreseeable future. 14. Any stipulation, and in particular, the figure for cost of capital, need only fall within the range of expert testimony and be supported by a preponderance of the evidence. Central Power and Light Company/Cities of Alice v. Public Utility Comm'n of Texas, 36 S.W.3d 547, 559 (Tex. App.-Austin 2000, pet. denied); City of El Paso v. Public Utility Comm'n of Texas, 883 S.W.2d 179, 183 (Tex. 1994). © 2015 Thomson Reuters. No claim to original U.S. Government Works. 29 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 15. In Generic Issues Associated with Applications for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule § 25.344, Docket No. 22344, Order No. 42 at 11 (Dec. 22, 2000), the Commission determined that a capital structure consisting of 60% debt and 40% equity was appropriate for T&D utilities. 16. In Docket No. 22344, Order No. 42 at 9-10, the Commission concluded there is a close correlation between return on equity and capital structure. 17. Although § 7(A)(1) of the ISA may require TCC to complete 95% of the requests for new service within one day, the ISA does not require TCC to report whether it complied with the standard. 18. PURA § 38.005(c) does not require utilities to maintain certain levels of training or personnel in order to comply with service and reliability standards. 19. Section 7.A.(2) of the ISA requiring TCC to replace 95% of security and street lighting outages within 72 hours does not contain a penalty. 20. The Commission may only 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 to the extent that the Commission finds the payment is reasonable and necessary for each item or class of items. PURA § 36.058(a) and (b). 21. To find that such an affiliate payment is reasonable and necessary, the Commission must: a. specifically find each allowed item or class of items is reasonable and necessary; and b. find that the price to the electric utility is not higher than the prices charged by the supplying affiliate to its other affiliates or divisions or to a non-affiliated person for the same item or class of items. PURA § 36.058(c). 22. In making a finding regarding an affiliate transaction, the Commission must: a. determine the extent to which the conditions and circumstances of that transaction are reasonably comparable relative to quantity, terms, date of contract, and place of delivery; and b. allow for appropriate differences based on that determination. PURA § 36.058(d). 23. The Commission must: a. carefully scrutinize all payments made by a utility to an affiliate, and b. disallow all such payments unless the utility showed that the payments met the statutory requirements. Railroad Commission of Texas v. Rio Grande Valley Gas Company, 683 S.W.2d 783 (Tex. App.-Austin 1984, no writ). 24. The specific provisions of PURA-and not the SEC-approved allocation factors-control the Commission's authority, and the statutory presumption is that payments made to affiliates are not allowed. Central Power and Light Co./Cities of Alice v. Public Utility Comm'n of Texas, 36 S.W.3d at 563. 25. The legislature has prohibited the Commission from considering for ratemaking purposes an expenditure “for legislative advocacy, made directly or indirectly, including legislative advocacy expenses in trade association dues.” PURA § 36.062(1). © 2015 Thomson Reuters. No claim to original U.S. Government Works. 30 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 25A. $53,289,706 of TCC's affiliate expenses are reasonable and necessary, and the price charged to TCC is not higher than the price charged by the supplying affiliate to its other affiliates or divisions or to nonaffiliated persons for the same item or class of items. 25B. To be approved by the Commission, a non-unanimous stipulation must comply with applicable law; be just, reasonable, and in the public interest; and be supported by a preponderance of the record evidence. City of El Paso v. Public Util. Comm'n, 883 S.W.2d 179, 183 (Tex. 1994). 25C. The non-unanimous stipulation providing for a disallowance of $10.5 million in affiliate expenses is just, reasonable, and in the public interest, and is supported by a preponderance of the record evidence. 26. Deleted. 27. Deleted. 28. Deleted. 29. Deleted. 30. The final order in Docket No. 22352, including finding of fact 98 and the reservation clause, allows the intervenors to challenge only the reasonableness of the amount of debt reacquisition charges incurred, and the reasonableness of the time period of their amortization. 31. The final order in Docket No. 22352 requires that debt-restructuring expenses incurred as a result of the mandate in PURA to separate business functions be recovered through transmission and distribution rates, subject to the specific challenges described in conclusion of law 30, above. 32. The Commission has discretion in deciding whether to allow post-test-year adjustments for known and measurable changes. Central Power & Light Company v. Public Utility Comm'n of Texas, 36 S.W.3d 547, 563 (Tex. App.-Austin 2000, pet. denied). 33. “Changes occurring outside the test period, if known, may be taken into consideration by the regulatory agency … to make the test year data as representative as possible of the cost situation that is apt to prevail in the future.” Suburban Utility Corp. v. Public Utility Comm'n, 652 S.W.2d 358, 366 (Tex. 1983). 34. Cost of service expenses in public utility ratemaking cases must be limited to “amounts actually realized or which can be anticipated with reasonable certainty.” Suburban Utility Corp., 652 S.W.2d at 362. 35. Unlike most other cost-of-service items that are subject to known and measurable adjustments, OPEB expenses in cost-of- service calculations are subject to a Commission rule that requires OPEB expenses to be based on “actual payments made.” P.U.C. SUBST. R. 25.231(b)(1)(H)(i). 36. The Applicant's proposed inclusion of non-historical amounts in its OPEB expense item is not permitted under the Commission's rules. Nothing in the provisions of P.U.C. SUBST. R. 25.231(b)(1)(H)(v) may be read to create an exception to the “actual payments made” requirement of P.U.C. SUBST. R. 25.231(b)(1)(H)(i). 37. P.U.C. SUBST. R. 25.231(b) establishes that in computing an electric utility's allowable expenses, the only measurement to be considered is the electric utility's historical test-year expenses as adjusted for known and measurable changes. 38. The Applicant is authorized to deduct its known and measurable expenses for the test year alone. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 31 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 39. The Commission established four categories of services that could be offered by a T&D utility: system services, discretionary services, petitioned services, and other services. P.U.C. SUBST. R. 25.342(f)(1). 40. A utility that provides a service that does not come within the definition of any of the first three categories may seek to treat that offering as an “other” service. 41. An offering may properly be characterized as an “other” service; however, only if the service satisfies specific provisions of the Commission's rule. “Other services” are “limited to those services that: (I) maximize the value of [T&D] system service facilities, and (II) are provided without additional personnel and facilities other than those essential to the provision of [T&D] system services.” P.U.C. SUBST. R. 25.342(f)(1)(D)(i)(I) and (II). If the offering satisfies that definition, then the utility is also required to “credit all revenues received from the offering of this service during the test year after known and measurable adjustments are made to lower the revenue requirement of the transmission and distribution utility on which the rates are based.” 42. Whatever its intention in approving the creation of the “other service” category, the Commission made clear that all revenues- and not net revenues-should be credited to the cost-of- service calculation. If, however, the costs and revenues of providing the other service are not included in the calculation of rates, then the test-year margins (revenues minus costs) received from the service should be credited to the cost-of-service calculation. 43. Deleted. 44. The Company failed to meet the legal requirements to recover $508,761 of the $679,344 in proposed salary adjustments and related taxes. 45. The Applicant met its burden of proof with regard to incentive compensation but only with respect to that portion relating to Operational Measures; the amount includible in the cost of service is 34% of $4.42 million. 46. TCC met its burden of proof with regard to pension expenses includible in the cost of service in the amount of $30,812. 47. The Applicant failed to meet its burden of proof on its proposed expense item for OPEB; the proposed expense item is not includible in the cost of service. 48. The group-insurance expense includible in the cost of service is the test-year actual cost of $3,741,039. 48A. The catastrophe-reserve expense includible in the cost of service is $900,000 annually for ten years until the catastrophe reserve reaches its maximum approved level of $9,000,000. 49. The Applicant proved DSM costs includible in the cost of service in the amount of $6,082,450. 50. PURA § 39.051(g), which states that, “[t]ransactions by electric utilities involving sales, transfers, or other disposition of assets to accomplish the purposes of this section are not subject to Section 14.101, 35.034, or 35.035,” does not limit the preclusions to one transaction. 51. $20,699,131 should be included in TCC's cost of service for ad valorem taxes in conformance with prior Commission precedent. 52. According to PURA § 36.060, an electric utility's income taxes shall be computed as though a consolidated return had been filed and the utility had realized its fair share of the savings resulting from that return, if the utility is a member of an affiliated group eligible to file a consolidated income-tax return, and it is advantageous to the utility to do so. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 32 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 53. Withdrawn by ALJ in Remand PFD. R1. TCC's federal-income-tax-expense in cost of service should be reduced by $2,322,545 to reflect TCC's share of AEP's consolidated tax savings. 54. TCC did not prove a need to include a bad-debt deferral account as part of an approved accounting procedure. 55. The distribution O&M-expense adjustments proposed by TCC are appropriate and should be approved. 56. TCC's proposed negative net salvage rates are reasonable. TCC's amended proposed depreciation expense should be adjusted to reflect the average service lives developed by Cities' witness Nancy Heller Hughes. 57. The possibility of decommissioning-expense under-funding is currently accounted for in the 10% contingency in P.U.C. SUBST. R. 25.231(b)(1)(F)(i). 58. Deleted. 59. The Applicant should not be granted a good-cause exception to P.U.C. SUBST. R. 25.342(f)(1)(D)(ii)(III), and should be required to credit to customers the full amount of the test-year margin of $2,708,122 resulting from TCC's transmission and construction-related ABD services. 60. PURA § 36.052 requires the Commission to consider “the quality of the utility's services” and “the quality of the utility's management” in establishing a reasonable return on invested capital as part of the PUC's “establishing an electric utility's rates.” 61. Deleted. 62. Deleted. 63. TCC's use of the A&E/4CP allocator to allocate nuclear-decommissioning costs was appropriate pursuant to P.U.C. SUBST. R. 25.344(h)(2)(E), because the Commission indicated a developing preference for the allocator in Docket No. 14965. 64. Based on PURA § 39.905(a)(3), which mandates energy-efficiency programs to achieve reductions of at least 10% of the electric utility's annual growth in demand, these program costs should be allocated on a demand basis. 65. PURA § 33.008 was enacted to maintain the same level of revenues for municipalities after the introduction of Customer Choice. 66. PURA § 33.008(b) requires that the municipal franchise fees be based on the number of kWh delivered within the municipal boundaries in order to maintain sufficient revenue levels for municipalities. 67. To meet the revenue requirement the municipal franchise fees should be allocated using a direct allocation based on a cents per kWh allocator within the municipalities. 68. Collecting the municipal franchise fees under the spread collection proposed by TCC is appropriate pursuant to PURA § 33.008(c), which requires that municipal franchise fees be collected from every retail customer served by the electric utility 69. PURA § 36.201 prohibits the Commission from establishing a rider that authorizes an electric utility to automatically adjust and pass through to the utility's consumers those costs that are incurred. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 33 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 70. Pursuant to P.U.C. SUBST. R. 25.181, energy-efficiency-program costs should not be recovered through an automatic adjustment, such as a separate rider. 71. An order amending P.U.C. SUBST. R. 25.303 was adopted by the Commission on October 6, 2004 and allows a separate nonbypassable charge for nuclear-decommissioning costs. 72. Deleted. 73. Deleted. 74. Deleted. V. Ordering Paragraphs 1. The proposal for decision prepared by the Administrative Law Judges of the State Office of Administrative Law Hearings is adopted to the extent consistent with this Order. 2. TCC's application is granted to the extent provided in this Order. 3. Before TCC's next rate case, TCC shall develop new load data reflecting its actual experience, and a new distribution field study. 4. TCC shall file tariff sheets consistent with this Order (compliance tariff) no later than 20 days after receipt of this Order. The compliance tariff, and all filings related to it, shall be filed in Tariff Control Number 31271, and shall be styled: Compliance Tariff Pursuant to Final Order in P.U.C. Docket No. 28840, (Application of AEP Texas Central Company for Authority to Change Rates). The filing shall include a transmittal letter stating that the tariffs attached are in compliance with the order, giving the docket number, date of the order, a list of tariff sheets filed, and any other necessary information. The timetable for review of the compliance tariff shall be established by the P.U.C. ALJ assigned to the tariff. In the event any sheets are modified or rejected, the applicant shall file proposed revisions to those sheets in accordance with the P.U.C. ALJ's notice. The effective date of the tariff shall be as determined in the written notice of approval by the P.U.C. ALJ. All subsequent filings in connection with the compliance tariff (i.e., requests for extensions, textual corrections, revisions) shall be filed in the same Tariff Control Number provided above, and styled as set forth above. After issuance of the final order, no further filings other than those pertaining to a motion for rehearing shall be made in this Docket. 5. The determination of the reasonableness and necessity of rate case expenses is severed into Docket No. 31433, Proceeding to Consider Rate Case Expenses Severed from Docket No. 28840 (Application of AEP Texas Central Company for Authority to Change Rates). 6. The entry of an order consistent with the Stipulations does not indicate the Commission's endorsement or approval of any principle or methodology that may underlie the Stipulations. Neither shall the entry of an order be regarded as binding precedent as to the appropriateness of any principle underlying the Stipulations. 7. All other motions, request for entry of specific findings of fact and conclusions of law, and any other requests for general or specific relief, if not expressly granted herein, are denied. SIGNED AT AUSTIN, TEXAS the _____ day of _______________ 2005. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 34 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... Footnotes 1 See Open Meeting Tr. at 159-60 (Jan. 13, 2005). 2 Application of Central and Southwest Corporation & American Electric Power Company, Inc. Regarding Proposed Business Combination, Docket No. 19265 (Nov. 18, 1999). 3 Docket No. 19265, ISA at Section 3.F.(1). 4 Direct Testimony of Michael Heyeck, TCC Ex. 6 at 9-12. 5 See Rebuttal Testimony of David Carpenter, TCC Ex. 66 at 28-31. 6 See Cities' Brief on Remand Issues at 3 (Mar. 24, 2005); CCR's Post-Hearing Brief on Merger Savings and Expenses at 3 (Mar. 24, 2005). 7 See, e.g., Direct Testimony of Michael Arndt, Cities Ex. 2 at 15; Direct Testimony of Ellen Blumenthal, CCR Ex.1 at 11-12. 8 See Docket No. 19265, Order (Nov. 18, 1999); Proposal for Decision at 10 (Oct. 1, 1999). 9 See SOAH Hearing Tr. at 240; Commission Hearing Tr. at 46-47; see also Direct Testimony of Thomas J. Flaherty in Docket No. 19265, CCR Ex.12 at 69. 10 Rebuttal Testimony of Mark G. Bailey, TCC Ex. 72 at 13. 11 Id. at 14. 12 Id.; SOAH Hearing Tr. at 2668. 13 Bailey Rebuttal at 14. 14 Id. at 14-15. 15 See Letter from John Williams, Attorney for AEP Texas Central Company, to Tammy Cooper, PUC, Regarding Depreciation Expense Adjustment (Jul. 29, 2005). 16 PFD at 34. 17 Id. at 11. 18 TCC Ex. 83 at 10. 19 PFD at 71. 20 Id. at 70. 21 See PFD at 72. 22 Public Utility Regulatory Act, TEX. UTIL. CODE ANN. §§ 11.001-64.158 (Vernon 1998 & Supp. 2005) (PURA). 23 PURA § 36.058(b), (c)(1). 24 See Central Power and Light Company/City of Alice et al. v Public Utility Commission of Texas, 36 S.W.3d 547, 567 (Holding that the Commission can disallow affiliate costs for failing to satisfy the requirements of PURA § 36.058(c)(2)); see also PURA § 36.006. 25 Second Order on Remand at 2 (Aug. 25, 2004). 26 Remand PFD at 11-12 (emphasis in original; footnote omitted). 27 Id. at 12. 28 Joint Motion for Implementation of Stipulation and Agreed Resolution Regarding Affiliate Expense Issues Based on the Evidentiary Record (Jun. 6, 2005). 29 The following parties did not oppose the NUS: Staff, Cities, Coalition of Commercial Ratepayers, Brazos Electric Power Cooperative, Inc., Occidental Chemical, South Texas Electric Cooperative, Inc., the City of Garland, Alliance for Retail Markets, and TXU Business Services. The State of Texas did not take a position on the NUS. 30 See OPC's Response to the Proposed Stipulation Regarding Affiliate Expenses (Jun. 13, 2005); Statement of Position of CPL Retail Energy, LP on the Nonunanimous Stipulation of Affiliate Costs (Jun. 13, 2005); Texas Legal Services Center's and Texas Ratepayer's Organization to Save Energy's Response to Order No. 28 (Jun. 13, 2005). 31 Act of May 25, 2005, 79 th Leg., R.S., 2005 Tex. Sess. Law Serv. Ch. 413 (effective Jun. 17, 2005). S.B. 1668 amended PURA 36.058, and provides, in part, that if the Commission finds that an affiliate expense is unreasonable, the Commission shall determine the reasonable level of expense and include that expense in the utility's cost of service. 32 Statement of Position of CPL Retail Energy, LP on the Nonunanimous Stipulation of Affiliate Costs at 4 (Jun. 13, 2005). 33 OPC's Response to the Proposed Stipulation Regarding Affiliate Expenses at 5 (Jun. 13, 2005). 34 City of El Paso v. Public Util. Comm'n, 883 S.W.2d 179, 183 (Tex. 1994). 35 Direct Testimony of Carol Szerszen, OPC Ex. 1A at 63. 36 Direct Testimony of Gerald W. Tucker, Cities' Ex. 4 at 20. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 35 APPLICATION OF AEP TEXAS CENTRAL COMPANY..., 2005 WL 6472784... 37 Direct Testimony of Dennis L. Thomas, CPL Ex. 1 at 48. This recommendation was based on CPL Retail's argument that the Commission should take a “top-down” approach in disallowing affiliate costs that would result in the Commission using TCC's previously approved affiliate costs (in its unbundled cost of service case, Docket No. 22356) “for the purposes of continuing current levels of affiliate expenses in this docket.” Id.; see also Closing Statement of CPL Retail Energy, LP at 6-7 (Mar. 24, 2005). 38 As noted by CPL Retail, “[t]he adjudication of affiliate costs in this case has followed a long and twisted path, perhaps unlike any other in the history of the Commission.” Statement of Position of CPL Retail Energy, LP on the Nonunanimous Stipulation of Affiliate Costs at 2 (Jun. 13, 2005). 39 See Letter filed by AEP TCC regarding proposed non-substantive corrections at 1-2 (Jul. 21, 2005). 40 Application of Central Power and Light Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22352, Order (Oct. 5, 2001). 41 Id. at Finding of Fact No. 98; see id., Stipulation and Agreement, at 9-10 (Mar. 26, 2001). 42 Id. 43 P.U.C. SUBST. R. 25.231(b). 44 Direct Testimony of Marshall Nadel, TCC Ex. 22 at 12. 45 In contrast to TCC's proposal, Staff witness Jacobs recommended a funding level of $799,433 annually, while Cities' witness Arndt recommended an annual funding level of $630,360. 46 Finding of fact 181A and conclusion of law 48A were added by the ALJs in their letter concerning clarifications and changes filed August 19, 2004. Additionally, conclusion of law 48A is modified to reflect that this amount is includible in TCC's cost of service rather than its rate base. 47 See 106-107. 48 Rebuttal Testimony of Randall Hamlett, TCC Ex. 67at 51; see also Commission Hearing Tr. at 550 (Mar. 4, 2005). 49 AEP is the parent company of TCC. 50 Petition of American Electric Power Company for Establishment of a Project to Modify Quality of Service Plan and Motion for Interim State of Plan Provisions, Docket No. 25157, Order (May 5, 2005). 51 PFD at 154. 52 AEP Texas Central Company Compliance Tariff Filing to Provide Competitive Metering Credit Pursuant to P.U.C. SUBST. R. 25.311 Docket No. 28559, Order (Dec. 30, 2003). 53 Rulemaking on Nuclear Decommissioning Funding Following the Sale or Transfer of Nuclear Generating, Project No. 29169, Order Adopting New § 25.303 (Oct. 6, 2004). 54 Schedule IV-J-2, TCC Ex. 2.2 at 2 of 27. 55 See PFD at 135-36. 56 See Letter from AEP TCC Regarding Non-Substantive Corrections (Jul. 21, 2005); Letter from AEP TCC Regarding Revised Number Run (Jul. 21, 2005). 57 See Letter from AEP TCC Regarding Nuclear Decommissioning Expenses Findings (Jul. 7, 2005). End of Document © 2015 Thomson Reuters. No claim to original U.S. Government Works. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 36 State Office of Administrative Hearings ~1~~ "•" ' • ~'11!""1\ff:'r\ ' : "; lj 1:. ~j 7iJ04 JUL - 2 M~ IQ: 0I PUBLIC urn 1n COHHISSION Shelia Bailey Taylor FILING CLERK Chief Administrative Law Judge July 1, 2004 TO: Stephen Journeay, Director Courier Pick-up Office of Policy Development William B. Travis State Office Building 1701 N. Congress, 7th Floor Austin, Texas 78701 RE: SOAH Docket No. XXX-XX-XXXX PUC Docket No. 28840 Application ofAEP Texas Central Company for Authority to Change Rates Enclosed are two copies of the Proposal for Decision (PFD) in the above-referenced case. Please file-stamp and return a copy to the State Office of Administrative Hearings for our records. Also enclosed is a disk containing an electronic copy of the PFD. By copy of this letter, the parties to this proceeding are being served with the PFD. Please place this case on an open meeting agenda for the Commissioners' consideration. The statutory deadline was extended in this proceeding to August 6, 2004. It is my understanding that you will be' notifying me and the parties of the open meeting date, as well as the deadlines for filing exceptions to the PFD, replies to the exceptions, and requests for oral argument. Sincerely, Katherine L. Smith It~ }" Paul D. Keeper z. ~l;;;e_j__. Administrative Law Judge Administrative Law Judge Enclosure xc: All Parties of Record (without disk) William P. Clements Building Post Office Box 13025 + 300 West 15th Street, Suite 502 + Austin Texas 78711-3025 (512) 475-4993 Docket (512) 475-3445 Fax (512) 475-4994 001 http://www.soah.state.tx.us 03lo SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 28840 APPLICATION OF AEP TEXAS § BEFORE THE STATE OFFICE CENTRAL COMPANY FOR § OF AUTHORITY TO CHANGE RATES § ADMINISTRATIVE HEARINGS PROPOSAL FOR DECISION I. INTRODUCTION A. History and Overview This is an application by American Electric Power Company (AEP) Texas Central Company (the Company, TCC, or Applicant) for approval of a change in the rates that it may charge for the transmission and distribution (T&D) of electricity. The Applicant is a T&D utility that provides service to a 44,000-square-mile area of south Texas. The service area includes the portion of Texas from just south of San Antonio to the Mexican border, and from Bay City west to Eagle Pass. Major cities in the Applicant's service area include Corpus Christi, McAllen, Harlingen, Laredo, and Victoria. The Applicant provides distribution services to about 785 ,000 electric connections, served by 28 retail electric providers (REPs). The Applicant's service area has a labor force population of just over 1 million. 1 AEP, the Applicant's parent company, is one of the largest investor-owned public utility holding companies in the United States. AEP became active in the Texas electric utility service market when AEP merged with a Texas electric utility holding company, Central and South West Corporation (CSW), in June 2000. 2 Prior to the merger, the Applicant was known as Central Power and Light Co., a name now held by the affiliated REP.3 1 TCC Ex. 4 at 6-7; TSLC/ROSE Ex. 8 at 2. 2 TCC Ex. 4 at 5; Application ofCentral and South West Corporation and American Electric Power Company, Inc. Regarding Proposed Business Combination, Docket No. 19265, Final Order (Nov. 18, 1999). 3 References in this proposal for decision to the REP will be to "CPL" or "CPL Retail." References in this proposal for decision to the former name of the Applicant will be to "Central Power and Light Co." 007 SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 122 PUC DOCKET NO. 28840 Although Dr. Goodfriend's survey and the portion of her testimony upon which it is based may be flawed, that criticism does not fit the remainder of her testimony. Therefore, the ALJs recommend a disallowance of one-half of Dr. Goodfriend's expenses, which reduces Cities' expenses to $935,595. The ALJ s also do not find a basis for denying either TCC or Cites their rate case expenses for appeals to the courts. T. Miscellaneous Issues TCC seeks to modify its Business Separation Plan (BSP) allowing it to separate by selling its generation assets outright, rather than placing them into an affiliated company, for purposes of determining its stranded costs. This issue appears to be uncontested. Therefore, the ALJ s recommend that TCC be allowed to modify its BSP to allow it to sell its generation assets, rather than placing them into an affiliated company. VII. QUALITY AND RELIABILITY OF SERVICE A. Quality of Service 1. Dr. Goodfriend's Testimony The issue of quality of service was raised as a major point of contention by Cities and its witness, Dr. Sarah Goodfriend. 470 Dr. Goodfriend's thesis was that the introduction of Customer Choice has had a negative effect upon the quality of service to end-use consumers. Among the causes of this degradation in quality, according to Dr. Goodfriend, is the fragmentation of the 470 Dr. Goodfriend' s credentials include her having obtained a Ph.D. in economics from the University ofNorth Carolina and her service with the Commission both as Director of the Economic and Regulatory Policy Division and, later, as a member of the Commission. .. 128 SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 123 PUC DOCKET NO. 28840 formerly integrated electric utility industry into providers with little direct relation to the ultimate electric utility customer. According to Dr. Goodfriend, however, PURA contains public policy controls about the tendency of suppliers to deteriorate service quality as a method of cost-cutting. 471 Dr. Goodfriend identified examples of this statutory recognition in PURA§§ 38.022, 39.101, and 36.052. These three statutes, Dr. Goodfriend asserted, reflect PURA standards that are instructive for an assessment of retail service quality. 472 PURA (and the regulations adopted pursuant to it) does recognize the need for the control of quality of service issues. However, much of that authority addresses the relationship between the end-use customer and its closest link in the Customer Choice system-the REP. The customer protection rules ofP.U.C. SUBST. R. 25.471-25.492 are among the best examples of the legislature's and the Commission's efforts at protecting the consumer in its primary utility relationship. As to Dr. Goodfriend's first two examples, PURA§§ 38.022473 and 39.101, 474 neither serve the function that she asserts and neither defines a direct statutory basis for evaluation of the Applicant's performance in this proceeding. 475 However, the third of Dr. Goodfriend's example, PURA§ 36.052, does serve that function. Specifically, PURA § 36.052 requires the Commission to consider "the quality of the utility's services" and "the quality of the utility's management" in establishing a reasonable return on invested capital as part of the PUC's "establishing an electric utility's rates." This proceeding is one in which the PUC is establishing an electric utility's rates. 471 Cities Ex. 8 at 16. 472 Cities Ex. 8 at 15. 473 Generally, PURA § 38.022 prohibits a utility from engaging in discriminatory practices with regard to persons that seek to compete with a utility. 474 PURA § 39.1O1 addresses the many consumer protection issues that the Commission later adopted in its consumer protection rules, P.U.C. SUBST. R. 25.471-25.492. 475 The Applicant's briefaccurately and appropriately identified the problems associated with Dr. Goodfriend' s reliance upon PURA §§ 38.022 and 39.101 as the statutory foundation for examining quality of service issues. However, the ALJs note that the Applicant's brief did not address Dr. Goodfriend's reliance upon PURA§ 36.052. 129 SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 124 PUC DOCKET NO. 28840 As with many Texas regulatory statutes, PURA § 36.052 is a general grant of legislative authority. The Commission is given broad power to provide the necessary administrative details. In response, the Commission has adopted three quality of service rules, found in P.U.C. SUBST. R. 25.51 ("Power Quality''), 25 .52 ("Reliability and Continuity of Service"), and 25.53 ("Emergency Operation Plan"). Each of these three rules measure important aspects of a utility's quality of public service. However, none of them measure the "consumer responsiveness" issues sought by Dr. Goodfriend or that may reasonably be derived from a fair reading of PURA § 36.052. In the absence of measures provided by either the statute or by Commission rules adopted from the statute, Dr. Goodfriend fashioned her own measures from other specific standards within other Commission's consumer protection rules. 476 Using these measures, Dr. Goodfriend sought to obtain data by conducting a survey of the utility's consumers with the greatest opportunity to evaluate the utility's quality of service performance-the REPs within the Applicant's service area. The universe of potential survey respondents was a bare 26 or 27 REPs, of which only nine returned completed survey forms. 477 In response to concerns expressed by some REPs, Dr. Goodfriend preserved the confidentiality of the individual respondents' data. The survey created a series of procedural issues even before Dr. Goodfriend testified. The Applicant sought to obtain information about the identities of the respondents, and Cities declined. In response, the Applicant filed a motion to compel the production or to strike the testimony of Dr. Goodfriend. The ALJ s ruled that Cities would have to produce the underlying data or deal with the challenge ofidentifying the non-objectionable portions of Dr. Goodfriend's pre-filed testimony. The parties agreed to allow Dr. Goodfriend to testify while Cities considered its options, and Dr. Goodfriend's direct and cross-examination were provisionally admitted into the record. Eventually, Cities opted to disclose the survey respondents' identities and to relate that information to the underlying survey response data. By agreement, the Applicant later submitted additional cross-rebuttal testimony that challenged the accuracy of the survey's underlying data, conclusions, 476 Cities Ex. 8 at 22. 477 Cities Ex. 8 at 25. ,- ' ~ r 130 SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 125 PUC DOCKET NO. 28840 and methodology. The Applicant's brief amplified that criticism. The Applicant has sought not only that the Commission disregard the entirety of Dr. Goodfriend' s survey-based analysis 478 but also that the Commission disallow the reimbursement of Dr. Goodfriend's portion of Cities' rate case expenses. 479 These developments were unfortunate. The ALJs consider Dr. Goodfriend's analysis to have been a good faith effort to bring to the Commission's attention an important issue. That the statute and the rules did not provide the details by which some quality of service issues could readily be measured required some creativity in setting those standards and obtaining that data. The ALJs believe that the provisions of PURA§ 36.052 may reasonably be interpreted to require a survey of the REPs. Indeed, Dr. Goodfriend reported that surveys are in the planning stages for at least one other T&D utility and for ERCOT. 480 Nonetheless, the ALJs concur with the Applicant that the survey methodology was seriously flawed and that conclusions drawn from the data cannot reasonably be supported under current legal standards. The ALJ s do not conclude that quality of service issues are irrelevant to this proceeding or that a survey of REPs (or others with opinions) is an inappropriate means of data gathering. Further, the ALJs' recommendation on this portion of Dr. Goodfriend's analysis does not reflect on the other portions of her testimony. 2. Other Quality of Service Evidence Dr. Goodfriend's survey was not the only example of survey evidence on this topic in this hearing. On cross-examination, the Applicant's witness, Harry Gordon, presented the results of four quarterly end-use customer surveys. Four thousand residential customers and 3,310 commercial 478 Applicant's Initial Brief at 124. 479 Applicant' Initial Brief at 117. 48 ° Cities Ex. 8 at 23. 131 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 2008 WL 727056 (Tex.P.U.C.) Slip Copy Application of AEP Texas Central Company for Authority to Change Rates 33309 XXX-XX-XXXX Texas Public Utility Commission March 4, 2008 ORDER ON REHEARING Before Smitherman, Chairman, Parsley and Hudson, Commissioners. BY THE COMMISSION: On November 9, 2006, AEP Texas Central Company (TCC) filed an application for authority to change rates pursuant to PURA, 1 Chapter 36, requesting an increase in base rates that would produce an annual base revenue increase of $62,709,174. During the course of this proceeding, TCC reduced this amount to approximately $49,952,000. 2 TCC also seeks to terminate the merger savings and rate reduction riders implemented in Docket No. 19365, 3 further increasing its revenues by $19,988,359 annually. Therefore, the total revenue increase sought by TCC in this proceeding is $69,940,359. The administrative law judges (ALJs) filed a proposal for decision (PFD) on August 30, 2007. In their PFD, the ALJs recommend that the Commission approve TCC's application, including termination of the merger savings and rate reduction riders, subject to the adjustments recommended in the Proposal for Decision (PFD). The recommendations reduce TCC's adjusted test year total revenue requirements from $581,127,359 to $531,123,478, a reduction of $50,004,479. TCC identified several number- run adjustments required to implement the ALJs' decision. 4 The Commission ordered Commission Staff to incorporate TCC's number-run corrections, which resulted in a revenue requirement of $540,707,774 or a reduction of $40,419,575 5 from TCC's original request. The Commission adopts the PFD issued by the ALJs, including the findings of fact and conclusions of law, with the number run corrections recommended by TCC in its exceptions to the PFD. 6 Findings of fact 23, 24 and 42 are modified to reflect Commission Staff's updated number runs. I. Findings of Fact Procedural History 1. AEP Texas Central Company (TCC or the Company) is an electric utility operating company and wholly owned subsidiary of American Electric Power Company (AEP), a public utility holding company. 2. TCC has been functionally unbundled, and its costs have been separated for accounting purposes among Transmission, Distribution, and Generation functions since the onset of retail competition in 2002. 3. TCC filed its application with the Public Utility Commission of Texas for authority to increase its transmission and distribution (T&D) rates on November 9, 2006, requesting an overall increase of approximately $62.7 million. 4. As part of its application, TCC gave notice of its intent to terminate approximately $20 million in credits to customers that are provided by separate riders implemented in connection with the Commission's approval of the AEP/CSW merger in © 2015 Thomson Reuters. No claim to original U.S. Government Works. 1 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) Application of Central and Southwest Corporation and American Electric Power Company, Inc. Regarding Proposed Business Combination, Docket No. 19265 (Nov. 18, 1999). 5. Concurrent with its filing with the Commission, TCC filed a similar petition and statement of intent with each incorporated city in its service area that has original jurisdiction over its retail rates. 6. Notice of TCC's application was published once a week for four consecutive weeks in newspapers having general circulation in each county in TCC's service territory and was completed on December 14, 2006. 7. Individual notice of the TCC's application was provided on November 9, 2006, to the Commission Staff and the Office of Public Utility Counsel (OPC). 8. On October 4, 2006, TCC mailed notice to each municipality in TCC's service area of its intent to change rates charged to retail electric providers (REPs) and certain end-use customers. 9. On November 8, 2006, TCC mailed notice of its petition and statement of intent to each municipality within TCC's service area. 10. Individual notice of the TCC's application was provided and completed by November 9, 2006, to all REPs who have been certified by the Commission and who serve end-use customers in TCC's service area. Notice was provided to all certified REPs. 11. Individual notice of the Application was provided to each party that participated in Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840 (Aug. 15, 2005), TCC's last T&D rate case. 12. The Commission referred this proceeding to the State Office of Administrative Hearings (SOAH) on November 14, 2006. The Commission issued its Preliminary Order setting forth the issues to be addressed in this proceeding on December 19, 2006. 13. The following parties were granted intervention: Alliance for Retail Markets (ARM); Cities served by TCC (Cities); City of Garland; Commercial Customer Group (CCG); CPL Retail Energy, L.P. (CPL); Efficiency Texas; Federal Executive Agencies (Department of the Navy); Occidental Power Marketing, L.P.; OPC; Reliant Energy Retail Services, LLC; South Texas Electric Cooperative; Sharyland Utilities, L.P.; State of Texas; Texas Cotton Ginners' Association; Texas Industrial Energy Consumers (TIEC); Texas Legal Services Corporation (TLSC); Texas Ratepayers Organization to Save Energy (Texas ROSE); Texas State Association of Electrical Workers; Oncor Electric Delivery Company; TXU Energy, Wholesale and Power Companies; and Wal-Mart Stores Texas, L.P. and Texas Retail Energy LLC (Wal-Mart). 14. TCC timely filed appeals with the Commission of the rate ordinances of the municipalities exercising original jurisdiction within its service territory. All such appeals were consolidated for determination in this proceeding. 15. TCC's application is based on a test year ending June 30, 2006. 16. On January 26, 2007, TCC filed an update to its rate filing that reduced its overall rate increase request by approximately $1.6 million. 17. When TCC filed its rebuttal case, it unilaterally decreased its total requested T&D base rate increase to approximately $50 million, a reduction of approximately $12 million from its initial request. This reduction included the impact of the January 26, 2007 update, as well as other reductions agreed to by the Company as a result of changed circumstances since its initial filing, or based on its review of Commission Staff and intervenor positions. 18. The hearing on the merits commenced on April 12, 2007 and lasted seventeen hearing days, concluding on May 4, 2007. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 2 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 19. TCC proposed an effective date of December 14, 2006, for the proposed rates. The effective date was suspended for 150 days until May 13, 2007. The Company agreed to further extend the effective date in order to allow the ALJs and the Commission to process the case. 20. On April 17, 2007, TCC filed notice of its intent to put into effect, under bond, the rates set out in attached, filed tariff sheets. The rates will produce an annual base revenue increase of $50,061,000. TCC stated its intent to implement such bonded rates on a system-wide basis on or after May 30, 2007, in order to maintain uniform system-wide rates throughout its service territory. 21. On May 15, 2007, the ALJs issued an interim order finding that a bonded rate is a changed rate under the ISA and PURA § 36.110; therefore, TCC is allowed to terminate the merger savings and the rate reduction riders ordered in Docket No. 19265, upon implementation of bonded rates. 22. On June 27, 2007, the Commission denied an interim appeal of the order identified in the above finding of fact 21, affirming the ALJs' ruling. Rate Base 23. TCC's used and useful total transmission plant in service (excluding general and intangible plant in service) is $912,831,763. 7 TCC's used and useful transmission plant in service net of accumulated depreciation (excluding depreciation on general and intangible plant in service) is $642,951,403. 8 24. TCC's used and useful total distribution plant in service (excluding general and intangible plant in service) is $1,446,115,221. 9 TCC's used and useful distribution plant in service net of accumulated depreciation (excluding depreciation on general and intangible plant in service) is $953,628,481. 10 25. TCC included in rate base a pension prepayment asset of $112.4 million. 26. The pension prepayment asset arises under Generally Accepted Accounting Principles (GAAP) in accordance with Statement of Financial Accounting Standards No. 87 (SFAS 87) and represents the amount by which the pension fund exceeds the accumulated pension obligations. 27. Investment income on the pension prepayment asset reduces pension cost calculated under SFAS 87. 28. Accounting in accordance with GAAP requires that both the balance sheet and income statement effects be taken into account. 29. The pension prepayment asset contains $22.799 million included in construction work in progress (CWIP). 30. Only the non-CWIP portion of the income earned on the pension prepayment asset is reflected in the total pension expense and the revenue requirement. 31. The pension prepayment asset should not be included in TCC's rate base to the extent that TCC's pension cost is capitalized to CWIP. 32. The pension prepayment asset of $112.4 million, less the $22.799 million portion included in CWIP, should be included in rate base. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 3 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 33. All of TCC's operations and maintenance (O&M) and administrative and general (A&G) expenses are included in its cash working capital calculation. 34. The leads and lags in paying these items, which give rise to the amounts recorded in Account 190, have been appropriately included in the calculation of rate base through this process. 35. Accumulated Deferred Federal Income Tax (ADFIT) of $323.9 million is reasonable and should be included in rate base. 36. In arriving at its adjusted test-year-end rate base, TCC reclassified $7.3 million in transmission projects that were classified as CWIP and that had not been closed out to plant-in-service as of June 30, 2006 but which were actually providing service to customers as of that date. 37. TCC also removed from rate base allowance for funds used during construction (AFUDC) of $368,625 related to the transmission projects that were reclassified. 38. The $7.3 million reclassification of these projects to plant-in-service is reasonable and should be adopted. 39. TCC's construction accounts payable were included in TCC's cash working capital calculation. Accordingly, the leads and lags associated with these construction accounts payable are appropriately included in the calculation of rate base. 40. Based on findings of fact 72 through 77, TCC's affiliate capital costs assigned to TCC Distribution should be reduced by $2,454,762, and affiliate capital costs assigned to TCC Transmission should be increased by $211,520. 41. TCC included in rate base $10.2 million in debt restructuring costs related to business separation. TCC also included in cost of service an annual amortization expense of $914,892 for amortization of these debt restructuring costs over a 15-year period. 42. TCC has a current cash working capital requirement of ($2,341,171), which includes $1,361,010 for transmission; ($2,660,226) for distribution; ($478,450) for metering; and ($563,505) for TDCS. 11 43. TCC's current working capital request reflects a modification of the monthly payment dates from TCC to American Electric Power Service Corporation (AEPSC) from the actual date of payment (usually the second or third working day after receipt) to the thirtieth day after receipt of the bill, as authorized by the TCC-AEPSC Service Agreement. 44. TCC must pay additional AEPSC financing costs for delaying payment of its bill from the second or third day until the thirtieth day after receipt. 45. TCC's own financing costs equal the financing costs charged to it by AEPSC. Thus, TCC will save the same amount of financing costs that AEPSC will charge it for delaying payments to AEPSC, so TCC will not incur any net increase in finance charges by delaying payment to AEPSC. 46. For TCC's cash working capital calculation, it is more appropriate to use the mid-point of the service period than the invoice date in the calculation of third-party expense lead days. 47. Cities' calculation of the third-party payment lead from samples of TCC's third-party invoices is reasonable and should be adopted, resulting in an additional third-party expense lead period of 2.26 days for distribution and an additional third-party expense lead period of 5.63 days for transmission. 48. The additional lead days for third-party expenses reduces TCC's request for cash working capital and rate base by $9,314,603. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 4 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 49. Beginning with calendar year 2005, TCC was required to implement for financial reporting purposes accounting for legal asset retirement obligations (AROs) associated with the cost of removal of asbestos from buildings in accordance with SFAS 143. 50. In its filing, TCC incorporated appropriate accounting changes for ratemaking purposes to account for the AROs associated with the cost of removal of asbestos from buildings in accordance with SFAS 143. This involved the establishment of offsetting ARO assets and liabilities, the inclusion of SFAS 143 depreciation and accretion in cost of service, and the exclusion of the cost of removal of asbestos from buildings from the net salvage component of the calculation of depreciation rates for Account 390. 51. TCC's use of SFAS 143 accounting for ratemaking purposes for the cost of removal of asbestos from buildings aligns the regulatory treatment with GAAP and should be approved. Return on Equity and Capital Structure 52. A return on equity of 9.96% will allow TCC a reasonable opportunity to earn a reasonable return on its capital investment. 53. TCC's energy conservation efforts, the quality of its services, the efficiency of its operations, and the quality of its management support a 9.96% return on equity. 54. A 9.96% return on equity is consistent with the level of financial risk associated with TCC's capital structure. 55. A reasonable application of the discounted cash flow, risk premium, and capital asset pricing models supports a return on equity of 9.96%. 56. TCC presented a revised pro forma cost of debt of 5.8586% based on updated information resulting from the retirement and refunding of its debt using the proceeds of the securitization approved in Application of AEP Texas Central Company for a Financing Order, Docket No. 32475, Financing Order (June 21, 2006). 57. The $1,669,612 in debt issuance costs related to Matagorda Navigation District No. 1 Pollution Control Bonds Series 2005 and B in 2005 were not incurred in connection with the issuance of transition bonds and are properly included in the cost of debt calculation in this docket. 58. TCC could not have included the $1,669,612 in cost of debt in Docket No. 33541, because that docket was a proceeding expressly designed for addressing only qualified costs. 59. TCC's cost of debt for purpose of this docket is 5.8586%. 60. The appropriate capital structure for purposes of setting rates in this proceeding consists of 60% debt and 40% equity. 61. A 60/40 capital structure is consistent with existing Commission precedent for T&D utilities. 62. A 60/40 capital structure is consistent with current rating agency expectations for TCC. 63. TCC's overall rate of return is as follows: Component % of Total Capitalization Cost of Capital Rate WACC (%) Long Term Debt 60.00% 5.8586% 3.5152% © 2015 Thomson Reuters. No claim to original U.S. Government Works. 5 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) Common Equity 40.00% 9.9600% 3.9840% Total 100.00% 7.4992% Cost of Service 64. AEPSC is the service company for the AEP System. It provides services to AEP's utility companies, including TCC. 65. TCC provided evidence supporting the primary allocation factors used to allocate costs and why such allocation factors are appropriate for the cost they support for fourteen classes of service involving affiliate transactions between AEPSC and TCC: customer service, distribution; transmission; external affairs; regulatory; Texas administration; information technology; business logistics; human resources; finance; accounting and strategic planning; internal support; safety and environmental; legal; and corporate communications. 66. TCC established cost trends, budget comparisons, benchmark studies, if available, or other proof suggested by the Commission's rate filing package Guiding Principles to support its level of requested affiliate costs. 67. TCC provided a schedule that shows how each allocator used by TCC is calculated and how often the calculation is updated. 68. The functions performed by AEPSC allow TCC to reduce its costs by capturing economies of scale. 69. AEPSC has been consistently reducing service company costs over the last several years, including costs to TCC. 70. The activities performed for TCC are necessary and provide direct benefits to TCC and its customers in terms of lower costs and reliable operations. 71. Of the approximately 90 discrete activities that define the full scope of AEPSC services, 19 activities were assessed to determine the potential for overlap of activities between AEPSC and TCC and other AEP utility subsidiaries. These 19 areas had activity descriptions that indicated potential similarity. Detailed assessment of these activities established that there was no duplication between AEPSC and TCC. 72. The manner in which AEPSC charges costs to TCC is properly designed to ensure that the equitable distribution and the allocation process are generally reasonable, except for the use of TCC's total assets allocator. 73. TCC uses a total assets factor to allocate the cost of certain services provided to itself and to other AEP affiliates by AEPSC. 74. After deregulation pursuant to Senate Bill 7, the Commission quantified TCC's stranded costs, and TCC chose to recover those costs through the securitization process rather than through a competition charge. The Commission issued financing orders allowing TCC to issue securitization bonds, providing TCC with the full amount of its stranded costs. Once the Commission issued the financing orders, TCC placed these regulatory assets on its books, assigned to TCC Distribution. 75. TCC included the regulatory assets noted in the above finding of fact and relating to stranded costs and securitization of generation assets in Allocator 58, its total assets allocator. 76. The inclusion of regulatory assets in Allocator 58 inflates the allocation of costs charged by AEPSC to the TCC distribution company. 77. Although TCC is required by accounting standards to include its regulatory assets on its balance sheet, these regulatory assets are not related to the provision of distribution service and should not be included in TCC's cost of service. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 6 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 78. TCC adequately reviews and questions the monthly services bill that it receives from AEPSC. 79. Any corrections requested by TCC or by other AEP affiliates, which AEPSC adopts, are applied to bills for all affiliate companies. Thus, a correction requested by another affiliate can benefit TCC. 80. TCC's adjustment to account for the creation of a new affiliate, Electric Transmission Texas, LLC (ETT) is reasonable. 81. TCC's adjustment to Allocator 70, Non-Electric Other Accounts Receivable, is reasonable. 82. TCC's inclusion of annual and long-term incentive compensation related to financial incentives in cost of service is unreasonable because it is not necessary for the provision of T&D utility services. 83. TCC reasonably determined group life insurance expense using an annualized June 2006 amount, with proper adjustments to cost of service to eliminate the portion of capitalized costs. 84. TCC reasonably determined savings plan (401k) expense using an annualized June 2006 amount, with proper adjustments to cost of service to eliminate the portion of capitalized costs, as adjusted in its rebuttal testimony. 85. TCC's pension expense of $1,627,376, which reflects a reduction of $456,000 for negative pension expense under SFAS 87 related to former generation employees, is reasonable and necessary. 86. TCC's requested adjusted test-year amount of $5,953,937 for postretirement benefits under SFAS 106, which included $886,264 in SFAS 106 transition adjustment amortization related to former generation employees, is reasonable. 87. Additional SFAS 106 postretirement benefit costs of $564,736 related to the former generation employees should be included in cost of service. 88. Total SFAS 106 postretirement benefit costs of $6,518,673 are reasonable and necessary. 89. A catastrophic property damage loss self-insurance program with an annual accrual of $1,300,000 and a target reserve amount of $13 million is in the public interest. 90. TCC's distribution O&M expenses, with the removal of the payment to the Public Utilities Board of Brownsville from distribution station maintenance expense, are reasonable and necessary. 91. TCC's transmission O&M expenses are reasonable and necessary. 92. TCC's request to recover the amount of its calendar year 2006 energy efficiency costs is known and measurable because TCC has used the actual 2006 costs to calculate its energy efficiency goal to be achieved by January 1, 2008. 93. For energy efficiency cost recovery, it is more reasonable to use costs incurred in a calendar year because such recovery more closely tracks statutory and regulatory energy efficiency goals. 94. It is reasonable for TCC's cost of service to include $6,334,949 in energy efficiency costs, as reflected in its calendar year 2006 costs. 95. TCC's proposed net salvage values for all FERC accounts are reasonable and appropriate estimates of future net salvage recoveries. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 7 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 96. In its application, TCC submitted a depreciation study based on plant-in-service as of December 31, 2005. This study reduced TCC's depreciation rates relative to the rates adopted by the Commission in Docket No. 28840. 97. TCC accepted Cities' recommended service life and survivor curves for two FERC accounts and net salvage for one FERC account. Differences exist between TCC and Cities and/or Commission Staff with respect to service life and survivor curves for seven FERC accounts and with respect to net salvage for 20 FERC accounts. 98. TCC's service life and survivor curves, as modified by the above finding of fact, are reasonable and should be adopted for all FERC accounts, except FERC accounts 365, 368, 371, and 373. 99. Commission Staff's recommendations should be adopted regarding the survivor curves (but not its proposed net salvage values), and the resultant depreciation rate should be adopted for FERC accounts 365, 368, and 371. 100. Cities' recommendation regarding the survivor curve and depreciation rate for FERC account 373 is reasonable and should be adopted. 101. TCC properly removed net proceeds from 1999 and 2005 building sales from consideration of net salvage value regarding FERC Account 390, because the net salvage received from sales of various buildings in those years were not generated in the ordinary course of TCC's business. 102. The inflation embedded in TCC's historical information will likely be experienced in the future. 103. TCC's historical information regarding cost and retirements of its assets properly imposes costs on the customers who benefit from the use of those assets. 104. The depreciation rates requested by TCC as set forth in TCC Exhibit 66 are reasonable and should be approved for all FERC accounts except FERC accounts 365, 368, 371, and 373. TCC's depreciation rates should be applied to the adjusted plant-in- service as of June 30, 2006, in order to calculate the reasonable and necessary depreciation accrual expense for cost of service. 105. The survival curves and resultant depreciation rates recommended by Commission Staff (but not its net salvage values) are reasonable and should be approved for FERC accounts 365, 368, and 371. The depreciation rates resulting from the survival curve recommended by Commission Staff should be applied to the adjusted plant-in-service as of June 30, 2006, in order to calculate the reasonable and necessary depreciation accrual expense for cost of service in FERC accounts 365, 368, and 371. 106. The survival curve and resultant depreciation rate requested by Cities is reasonable and should be approved for FERC Account 373. The depreciation rate resulting from the survival curve requested by Cities as set forth in TCC Exhibit 66 should be applied to the adjusted plant-in-service as of June 30, 2006, in order to calculate the reasonable and necessary depreciation accrual expense for cost of service in FERC account 373. 107. Regarding sales of certain buildings in FERC Account 390, TCC removed from its depreciation study the proceeds from sales in 1999 and 2005, along with the associated costs of removal, and the original costs of the buildings. 108. The approach TCC used regarding sales of buildings in FERC Account 390 is reasonable, comports with the applicable accounting requirements, and provides the full benefit of the sale, including the gain, to customers, through reduction of rate base and associated reduction of the depreciation accrual. 109. TCC experienced 50% or higher net salvage results for FERC Account 390 in six of 22 years (1984-2005) included in its depreciation study. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 8 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 110. After 1999, 2005 was the first year in which TCC received net gains from salvage of buildings in FERC Account 390 that exceeded 50%. 111. The last year that a net salvage rate of greater than 50% occurred for FERC Account 390 was 1994. 112. TCC's net salvage results for 1999 and 2005 from sales of buildings are not likely to recur regularly on the same scale. 113. As part of its implementation for ratemaking purposes of SFAS 143 ARO accounting for the legal obligations related to costs of removal of asbestos from buildings, TCC included an accretion expense of $73,000, which substitutes for the cost of removal of asbestos previously included in the cost of removal for depreciation purposes. 114. Because it is reasonable to implement for ratemaking purposes SFAS 143 ARO accounting for the legal obligations related to costs of removal of asbestos from buildings, the related accretion amount is reasonable and necessary. 115. TCC appropriately collected late payment charges in compliance with the existing tariff, using reasonable accounting practices. 116. During the test year, TCC performed transmission-related construction services, engineering, procurement, and other related construction services for the Lower Colorado River Authority (LCRA) on lines that will be owned by LCRA. 117. TCC is exiting the third-party construction business; thus, it reduced its test year margins (revenues less expenses) of $3.3 million down to $789,714, as a known and measurable adjustment to miscellaneous revenues. 118. TCC's adjustment to miscellaneous revenues to account for the decrease in third-party margins is reasonable, known, and measurable. 119. TCC is a member of an affiliated group eligible to file a consolidated federal income tax return. 120. The amount of the fair share of consolidated federal income tax savings allocated to TCC is $1,901,184 before gross up and $2,924,898 after gross up. 121. Ad valorem property taxes in the amount of $27,853,898 are reasonable and necessary expenses. 122. The transmission cost of service (TCOS) included in the final distribution cost of service should be synchronized with the transmission rates applied to the TCC distribution function based on the TCOS established for the TCC transmission function as a result of this case. 123. TCC's historical actual bad debt cost for the test year of $138,776 should be included in cost of service. 124. TCC's proposal to include $328,009 in rates for business and economic dues was unsupported by the preponderance of the evidence because some dues may have included legislative advocacy or lobbying expenses. 125. It is reasonable to sever from this proceeding issues related to Cities' and TCC's recovery of rate case expenses. Load Research 126. In Application of AEP Texas Central Texas Company for Authority to Change Rates, Docket No. 28840 (Aug. 15, 2005), TCC was ordered to file TCC-specific load research data in its next rate case. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 9 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 127. TCC filed company-specific load research data in this case. 128. TCC employed industry-accepted standard load research practices in developing the load research samples and demand estimates, which accurately represent the TCC rate class populations. 129. The overall result of TCC's load research study is a reasonable estimate of class demands for use in allocating costs in this case. 130. The changed load characteristics result from class usage changes. 131. The final numbers produced by TCC's load research study consistently represent the customers that moved from the non- interval data recorder (IDR) class to the IDR class as if they were members of the IDR class for the entire test year. Cost-of-Service Study 132. In Docket No. 28840, the Commission's Order required TCC to perform a new distribution field study. TCC completed that study and used its results to allocate demand related distribution costs in the cost-of-service study used in this docket. 133. The cost-of-service studies performed by TCC were performed in a manner that is consistent with that used in TCC's most recent rate case, are reasonable, and should be approved. 134. It is appropriate to use a 100% demand allocator for distribution accounts 364 through 368. 135. The data in the cost-of-service study supporting the development of charges for IDR metered customers, the schedules, and workpapers collectively support the changes proposed by TCC for IDR metered customers. 136. All customers within a class pay the same metering charge, regardless of the type of meter they use. 137. IDR-metered customers receive a higher Customer Charge than non-IDR-metered customers in the same class, primarily due to the complexity of preparing the IDR-metered customer's bill. Rate Design 138. TCC's rate design uses the same customer classes ordered by the Commission in Docket No. 22344, Order No. 40. 139. TCC's proposed textual changes and changes to the standard allowance values in the Facilities Extension Schedule are unopposed and are reasonable. 140. TCC's proposed pilot program for front-of-the-lot subdivisions, as modified by Commission Staff, is reasonable. 141. TCC's request to continue to provide facilities rental services under the Distribution Voltage Facilities Rental Service and System Integral Facilities Rental Service tariff schedules, as updated in this proceeding, until January 1, 2011, is unopposed and is reasonable. 142. The increases assigned to each of the generic rate classes are the result of moving each rate class to unity (i.e., an equalized rate of return or full recovery of allocated costs). © 2015 Thomson Reuters. No claim to original U.S. Government Works. 10 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 143. Applying an across-the-board increase when actual cost data is available is contrary to Commission precedent, unjustified, and should be rejected. 144. An adjustment to the revenue allocation for the intra-class functions is neither necessary nor appropriate. 145. Modification of the customer service, metering, and distribution function revenue requirements unjustifiably strays from the equalized cost-of-service study. 146. TCC's proposed changes to the customer charges are based on cost, are consistent with Commission precedent, and should be approved. Riders 147. TCC's proposed Municipal Franchise Fee Adjustment-City (MFFA-C) rider would be used to reflect a change to a specific municipality's franchise fee. 148. Under the proposed MFFA-C rider, municipal franchise fee adjustment that applies to a specific municipality would be applied to bills of retail customers who are located within the specific city's municipal limits. 149. TCC's proposed Rider MFFA-C should be rejected as it would create confusion with potentially over 100 different rates. 150. Having different rates in each municipality in TCC's service territory is contrary to the Commission's desire for uniform, simple rates. 151. The Commission has a pending rulemaking to change the energy efficiency rules in Amendments to Energy Efficiency Rules and Templates, Project No. 33487, which was put on hold pending proposed legislation. 152. It is premature to adopt a new method of energy efficiency cost recovery, such as the rider TCC proposed in its application, until the Commission adopts new rules, as required by recent legislation. Discretionary Service Fees 153. Discretionary service fees are billed to the REPs or distribution end-use retail customers for the cost of performing a specific distribution service requested by the REP or end-use retail customer. 154. Discretionary service fees are charged to the party that causes the cost to be incurred so that other parties not requiring the service do not have to pay for the cost through base rates. 155. All TDUs must offer the discretionary services defined in the Standardized Discretionary Services Section of the Tariff. 156. TCC's proposed discretionary service fees are based on the cost to perform each discretionary service. 157. TCC's proposed discretionary fees, including the disconnect and reconnect fees, are reasonable and should be approved. Tariff Formatting and Language 158. Several areas in TCC's filed Standardized Discretionary Services portion of its tariff do not conform to the pro forma tariff approved in Project No. 29637. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 11 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 159. The formatting changes recommended by Commission Staff should be made in order to comply with the Commission's rule. 160. Commission Staff's recommended changes to the proposed Broken Meter Seal and After Hours Temporary Removal fees should be made. 161. Commission Staff's recommended language changes to Section 6.2.3.3.7, Meter Enclosure Seal Breakage, should be approved. Termination of the ISA Riders 162. Pursuant to the ISA entered in Docket No. 19265, the merger savings and rate reduction riders related to the merger of AEP and Central and Southwest Corporation (CSW) terminate with a change in TCC's rates. 163. TCC was allowed to terminate the Docket No. 19265 merger savings and rate reduction riders upon its filing of bonded rates, effective May 30, 2007. 164. TCC should continue to be allowed to terminate the Docket No. 19265 merger savings and rate reduction riders upon the entry of a final order in this proceeding that changes TCC's rates. II. Conclusions of Law 1. TCC is an electric utility as defined by PURA § 31.002, and, therefore, it is subject to the Commission's jurisdiction under PURA §§ 32.001, 33.051, and 36.102. 2. TCC is a T&D utility as defined in PURA § 31.002(19). 3. SOAH has jurisdiction over all matters relating to the conduct of the hearing in this case, including the preparation of a Proposal for Decision, pursuant to PURA § 14.053 and TEX. GOV'T CODE ANN. § 2003.049(b). 4. TCC provided adequate notice of this proceeding in compliance with P.U.C. PROC. R. 22.51. 5. Pursuant to PURA § 33.001, each municipality in TCC'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. 6. The Commission has jurisdiction over an appeal from a municipality's rate proceeding pursuant to PURA § 33.051. 7. PURA § 36.110 authorizes a utility to put changed rates, not to exceed its proposed rates, into effect in all areas in which the utility sought to change its rates under bond if the Commission fails to make its final determination before the 151st day after the date that the proposed change would otherwise have gone into effect had the operation of the proposed rates not been suspended. TCC's proposed effective date for its proposed rates was December 14, 2006, because TCC was authorized to implement a changed rate under bond effective with usage beginning on May 14, 2007, subject to refund, because the Commission did not make its final determination of rates on or before May 13, 2007. 8. The effective date of the change in rates approved in this case was extended to be consistent with P.U.C. SUBST. R. 25.241(i) and by agreement of TCC, consistent with P.U.C. PROC. R. 22.33(c). © 2015 Thomson Reuters. No claim to original U.S. Government Works. 12 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 9. The rates approved in this proceeding are based on original cost, less depreciation, of property used and useful to TCC, consistent with PURA § 36.053. 10. TCC's treatment of its debt restructuring costs conforms to the determinations the Commission made regarding these costs in its orders in Application of Central Power and Light Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Commission Substantive Rule 25.344, Docket No. 22352 (Oct. 5, 2001) and Docket No. 28840 (Aug. 15, 2005), should be approved. 11. PURA § 36.065(a) provides that electric utility rates shall include “expenses for pensions and other postemployment benefits, as determined by actuarial or other similar studies in accordance with generally accepted accounting principles, in an amount the regulatory authority finds reasonable.” 12. TCC's requested pension expense, which accounts for negative pension expense under SFAS 87 related to former generation employees, is in accordance with PURA § 36.065. 13. TCC's requested adjusted test-year amount of postretirement benefits under SFAS 106, which included a transition adjustment amortization related to former generation employees, is in accordance with PURA § 36.065. 14. GAAP, with respect to pension cost, are determined in accordance with SFAS 87 and SFAS 88. 15. P.U.C. SUBST. R. 25.231(c)(2)(D) prohibits including in rate base the portion of TCC's pension prepayment asset capitalized to CWIP. 16. Inclusion in rate base of TCC's approved pension prepayment asset and offsetting accumulated deferred income taxes comports with GAAP and PURA § 36.065. 17. No modification would be proper to the rate base treatment or to the 15-year amortization to cost of service of the debt restructuring costs TCC incurred in connection with business separation ordered in Docket Nos. 22352 and 28840. 18. The return on equity and overall return authorized in this proceeding are consistent with the requirements of PURA §§ 36.051 and 36.052. 19. PURA § 39.302(4) allows “the costs of issuing, supporting, and servicing transition bonds and any costs of retiring and refunding the electric utility's debt and equity securities in connection with the issuance of transition bonds” to be included in qualified up-front costs of securitization. Costs in the amount of $1,669,612 that TCC incurred in issuing Matagorda Navigation District No. 1 Pollution Control Bonds Series 2005 and B in 2005 were not incurred in “retiring and refunding. . . [TCC's] debt and equity securities in connection with the issuance of transition bonds,” which occurred in late 2006. 20. The costs in the amount of $1,669,612 initially incurred in issuing Matagorda Navigation District No. 1 Pollution Control Bonds Series 2005 and B in 2005 are properly included in TCC's cost of debt calculation. P.U.C. SUBST. R. 25.231(c)(1)(C)(i). 21. TCC's decisions to retire and refund debt using the proceeds of the securitization were prudent under the prudence standard articulated in Application of Gulf States Utilities Company to Change Rates, Docket No. 7195, 14 P.U.C. Bull. 1943, 1969-1970, 2429 (CoL 14) (May 16, 1998). 22. For ratemaking purposes, P.U.C. SUBST. R. 25.231(c)(1)(C)(i) requires the cost of debt to be “the actual cost of debt at the time of issuance, plus adjustments for premiums, discounts, and refinancing and issuance costs.” 23. The affiliate expenses included in TCC's rates are consistent with the requirements of PURA § 36.058. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 13 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 24. PURA § 36.065(a) authorizes an unbundled transmission and distribution utility to include in rates the “pension and other postemployment benefits” related to the employees of its predecessor's generation function. 25. As used in PURA § 36.065(a), “pension and other postemployment benefits” (OPEB) includes pension costs under SFAS 87, postretirement benefits under SFAS 106, and postemployment benefits under SFAS 112. 26. Pursuant to P.U.C. SUBST. R. 25.231(b)(1)(H), OPEB shall be included in an electric utility's cost of service for ratemaking purposes based on actual payments made. 27. PURA § 36.064 permits a utility to self-insure “potential liability or catastrophic property loss, including windstorm, fire, and explosion losses, that could not have been reasonably anticipated and included under operating and maintenance expenses.” The Commission shall approve a self-insurance plan under that section if it finds the coverage in the public interest, the plan, considering all of its costs, is a lower cost alternative to purchasing commercial insurance, and ratepayers receive the benefits of the savings. 28. A catastrophic property damage loss self-insurance program with an annual accrual of $1,300,000 and a target reserve amount of $13 million is in accordance with PURA § 36.064 and P.U.C. SUBST. R. 25.231(b)(1)(G). 29. PURA § 36.060 requires the use of a consolidated tax savings (CTS) adjustment when computing an electric utility's federal income taxes. 30. PURA §§ 36.061 and 36.062 and P.U.C. SUBST. R. 25.231(b)(2)(A) disallow recovery of legislative advocacy expenses included in professional or trade association dues. 31. PURA § 39.903(g) no longer applies to TCC, which is subject to competition. 32. TCC's proposed level of energy efficiency funding complies with PURA § 39.905(f). 33. P.U.C. SUBST. R. 25.342(f)(1)(D)(ii)(III) requires a utility to “credit all revenues received . . . during the test year after known and measurable adjustments are made to lower the revenue requirement” of the T&D utility. TCC's proposal to make a known and measurable change to its test year margins of $3.3 million and then reduce its revenue requirement by the adjusted margin of $789,714 complies with this requirement. 34. TCC's proposed rate design and cost allocation are consistent with the requirements of PURA §§ 36.003 and 36.004. 35. Termination of the rider credits associated with the Commission's order in Docket No. 19265, contemporaneous with implementation of bonded rates in this proceeding, is consistent with the provisions of PURA § 36.110 and with the express language of the Integrated Stipulation and Agreement approved by the Commission in Docket No. 19265. III. Ordering Paragraphs The proposal for decision prepared by the SOAH ALJs is adopted to the extent consistent with this Order. 1. TCC's application is granted to the extent provided in this Order. 2. All issues relating to the recovery of Cities' and TCC's rate case expenses are severed from this proceeding and consolidated with Proceeding to Consider Rate Case Expenses Severed from Docket No. 33310 (Application of AEP Texas North company for Authority to Change Rates, Docket No. 34301 (pending)). © 2015 Thomson Reuters. No claim to original U.S. Government Works. 14 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) 3. TCC shall file tariff sheets consistent with this Order no later than 20 days after receipt of this Order. The compliance tariff, and all filings related to it, shall be filed in Tariff Control Number 35093, and shall be styled: Compliance Tariff of AEP Texas Central Company Pursuant to Final Order in P.U.C. Docket No. 33309, (Application of AEP Texas Central Company for Authority to Change Rates). The filing shall include a transmittal letter stating that the tariffs attached are in compliance with the order, giving the docket number, date of the order, a list of tariff sheets filed, and any other necessary information. No later than 10 days after the date of the tariff filings, Commission Staff shall file its comments recommending approval, modification, or rejection of the individual sheets of the tariff proposal. Responses to the Commission Staff's 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. Pursuant to PURA § 36.110(d) TCC shall (1) refund or credit bills for money collected under the bonded rates put into effect on or after May 30, 2007 in excess of the base rate revenue increase ordered in this docket; and (2) include interest on that money at the current approved Commission approved interest rates. TCC shall file in Tariff Control Number 35093 calculations supporting the amounts and a tariff to implement the refund or credit. 5. The tariff sheets shall be deemed approved and shall be become effective upon 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, TCC shall file proposed revisions of those sheets in accordance with the Commission's letter within 10 days of the date of that letter, and the review procedure set out above shall apply to the revised sheets. 6. Copies of all tariff-related filings shall be served on all parties of record. 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 AT AUSTIN, TEXAS the 4th day of March 2008. Final Order Schedule I Revenue Requirement COMPANY NAME AEP TEXAS CENTRAL COMPANY TEST YEAR END 30-Jun-06 Test Year Total Company Adjustments Company Adjusted Test Recommended Adjust. Final Order Adjusted To Test Year Year Total Electric To Co. Request Total Electric (a) (b) (c) (d) (e)=(c)+(d) REVENUE REQUIREMENT Operations & Maintenance 296,033,365 (36,179,627) 259,853,738 (14,328,513) 245,525,225 Depreciation & 96,502,951 (20,891,707) 77,611,244 (2,781,840) 74,829,404 Amortization Expense © 2015 Thomson Reuters. No claim to original U.S. Government Works. 15 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) Taxes Other Than Income 80,617,871 (277,099) 80,340,772 (4,416,323) 75,924,449 Taxes Federal Income Tax 58,197,809 (21,306,539) 35,036,738 (8,096,772) 26,940,967 Return on Invested Capital 205,700,718 (77,415,253) 128,285,485 (10,797,736) 117,487,730 TOTAL REVENUE 739,052,714 (156,070,225) 581,127,968 (40,420,183) 540,707,774 REQUIREMENT MINUS. OTHER (38,539,566) (38,539,566) (38,539,566) REVENUE TOTAL ADJUSTED 700,513,148 (156,070,225) 542,588,392 (40,420,183) 502,168,208 REVENUE REQUIREMENT Schedule II TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE Schedule III Invested Capital Test Year Total Company Adjustments Company Adjusted Test Recommended Adjust. Final Order Adjusted To Test Year Year Total Electric To Co. Request Total Electric (a) (b) (c) (d) (e)=(c)+(d) INVESTED CAPITAL Plant in Service 2,658,106,172 6,080,094 2,664,186,266 (2,243,242) 2,661,943,024 Accumulated Depreciation (867,692,603) 613,007 (867,079,596) 0 (867,079,596) Net Plant in Service 1,790,413,589 6,693,101 1,797,106,870 (2,243,242) 1,794,563,428 Construction Work in 0 0 0 0 Progress Plant Held for Future Use 0 0 0 0 Working Cash Allowance 6,605,495 0 6,605,495 (8,942,063) (2,336,568) Materials and Supplies 21,796,582 (6,015,953) 15,780,609 0 15,780,809 Prepayments 114,759,964 0 114,759,964 (22,799,000) 91,980,984 Regulatory Assets 1,686,675,388 (1,665,490,091) 21,185,297 0 21,185,297 SFAS 109 Reg. Liability (30,411,435) 0 (30,411,435) (30,411,435) Deferred Federal Income (1,022,891,875) 698,972,101 (323,919,774) 0 (323,919,774) Taxes © 2015 Thomson Reuters. No claim to original U.S. Government Works. 16 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) Customer Advances for 0 0 0 0 Construction Customer Deposits 688,850 0 688,850 0 688,850 Asset Retirement (1,201,634) 9,402 (1,192,232) 0 (1,192,232) obligations Investment Tax Credits (116,069) 0 (116,069) 0 (116,069) TOTAL INVESTED 2,566,318,815 (965,831,440) 1,600,487,375 (33,964,305) 1,586,503,070 CAPITAL RATE OF RETURN 8.0154% 8.0154% 7.5000% RETURN ON INVESTED 205,700,718 128,285,465 117,487,730 CAPITAL Schedule IV Taxes Other Than FIT Test Year Total Company Adjustments Company Adjusted Test Recommended Adjust. Final Order Adjusted To Test Year Year Total Electric To Co. Request Total Electric (a) (b) (c) (d) (e)=(c)+(d) TAXES OTHER THAN FIT Ad Valorem Taxes 30,985,808 953,313 31,939,121 (4,123,063) 27,816,058 Payroll Taxes 3,302,653 157,097 3,459,750 0 3,459,750 Sales and Use (557,545) 1,042,850 485,305 485,305 Federal Excise\ St. Lic. 1,009 0 1,009 1,009 Municipal Franchise 41,044,325 (396,142) 40,646,183 40,646,183 Taxes Franchise Tax 5,841,621 (5,841,621) 0 Gross Margin Taxes 0 3,809,404 3,809,404 (293,280) 3,516,144 TOTAL TAXES OTHER 80,617,871 (277,098) 80,340,772 (4,416,323) 75,924,449 THAN INCOME TAXES Final Order Schedule II-B-1 TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE Final Order - Schedule II-B-5 TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE © 2015 Thomson Reuters. No claim to original U.S. Government Works. 17 Application of AEP Texas Central Company for Authority to..., 2008 WL 727056 (2008) TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE Final Order Schedule II-B-1 TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE Final Order Schedule II-B TABULAR OR GRAPHIC MATERIAL SET FORTH AT THIS POINT IS NOT DISPLAYABLE Footnotes 1 Public Utility Regulatory Act, TEX. UTIL. CODE ANN. §§ 11.001 - 64.158 (Vernon Supp. 2007) (PURA). 2 TCC Ex. 78, RWH-1R. 3 See Application of Central and Southwest Corporation and American Electric Power Company, Inc. Regarding Proposed Business Combination, Docket No. 19365, Integrated Stipulation and Agreement (Nov. 18, 1999). 4 AEP Central Company's Exceptions to the Proposal for Decision and Request for Number Running Corrections, Attachment E at 87-91 (Sept. 20, 2007). 5 See generally Commission Staff Final Number Run - Final Order - Schedule 1 - Total Revenue Requirement - Column Total for Final Order Adjusted Total Electric (Feb. 5, 2008). 6 See generally Corrected Page to the Proposal for Decision and Request for Number Running (Sept. 20, 2007). 7 See Docket No. 33309 - Final Order Number Run - (Transmission Model) Schedule II-B-1, Rate Base Accounts - Plant Test Year Ending 6/30/2006 - Total Transmission Distribution Plant Gross (Filed February 5, 2008) 8 Id.- Schedule II-B-5 - Total Transmission - Distribution Plant - Net 9 Id. (Distribution Model) Schedule II-B-1 10 Id. (Distribution Model) Schedule II-B-5 11 See - P.U.C. Docket No. 33309 - Final Number Runs - Schedule IIB - Summary of Rate Base - Cash Working Capital (Reference Schedule II-B-9) Page 1 of 1 (February 5, 2008). End of Document © 2015 Thomson Reuters. No claim to original U.S. Government Works. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 18 PUC DOCKET NO. 34800 SOAH DOCKET NO. XXX-XX-XXXX APPLICATION OF ENTERGY § GULF ST ATES, INC. FOR § AUTHORITY TO CHANGE RATES § AND TO RECONCILE FUEL § COSTS § ORDER 1 This order addresses the application of Entergy Gulf States, Inc. (EGSI) for authority to change rates and reconcile fuel costs. The docket was processed in accordance with applicable statutes and Public Utility Commission of Texas rules. EGSI, Commission Staff, the Office of Public Utility Counsel (OPC), the Community Associations of the Woodlands (CATW), the Entergy Texas, Inc. Service Area Cities' Steering Committee (Cities), the State of Texas, Texas Industrial Energy Consumers (TIEC), Texas Legal Services Center (TLSC), Texas Ratepayers' Organization to Save Energy (Texas ROSE), Wal-Mart Stores Texas, LLC , through their duly authorized representatives (Wal-Mart) (collectively, signatories) filed a stipulation and settlement agreement that resolves all of the issues in this proceeding. The Kroger Company and TX Energy, LLC did not sign the stipulation and do not oppose it. Consistent with the stipulation, EGSI's application is approved. The Commission adopts the following findings of fact and conclusions of law: I. Findings of Fact Procedural History 1. On September 26, 2007, EGSI filed an application for approval of: ( 1) base rate tariffs and riders designed to collect a total non-fuel revenue requirement for the 1 On December 31, 2007, EGSI jurisdictionally separated pursuant to * 39.452( e) of the Public Utility Regulatory Act (PURA), TEX. UTIL. CODE ANN. Title 2 and Entergy Texas, Inc. (ETI) succeeded to EGSI's certificate of PUC Docket No. 34800 Order Page 2of15 SOAH Docket No. XXX-XX-XXXX Texas retail jurisdiction of $605 million; (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying EGSI's application; (3) a request for final reconciliation of EGSI's fuel and purchased power costs for the reconciliation period from January 1, 2006 to March 31, 2007, as well as deferred costs from prior proceedings; and (4) certain waivers to the instructions in RFP Schedule V accompanying EGSI's application. 2. The 12-month test year used in EGSI's application ended on March 31, 2007. 3. EGSI 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 EGSI's Texas service territory. EGSI also mailed notice of its proposed rate change to all of its customers. Additionally, EGSI timely served notice of its statement of intent to change rates on all municipalities retaining original jurisdiction over its rates and services. 4. The following parties were granted intervenor status in this docket: OPC, Alliance for Retail Markets (ARM), CATW, Cities, Kroger Company, State, TIEC, TLSC, Texas ROSE, TX Energy, LLC, and Wal-Mart.2 Commission Staff was also a participant in this docket. 5. On October 1, 2007, the Commission referred this case to the State Office of Administrative Hearings (SOAH) for processing. 6. EGSI appealed the rate decisions adopted by the Cities of Chester, Woodville, Ames, Dayton, Devers, Liberty, New Waverly, Riverside, Trinity, Bedias, Bremond, Caldwell, Calvert, Franklin, Madisonville, Somerville, Patton Village, Cut and Shoot, Willis, Plum Grove, Shepherd, Oak Ridge North, Normangee, Daisetta, Hardin, Corrigan, Groveton, Anderson, Kosse, North Cleveland, Woodloch, Midway, Panorama Village, Taylor Landing, Rose Hill Acres, China, Hearne, Bevil Oaks, Colmesneil, Kountz, Nome, Lumberton, and Todd Mission. convenience and necessity for its Texas retail jurisdiction. For continuity and ease of reference, EGSI, Commission Staff, and intervenors have continued to make reference to EGSI for purposes of pleadings in this docket. 2 OPC, ARM, Cities, Kroger Company, State, and TIEC were granted party status on October 22, 2007. See Prehearing Conference Tr. at 6. PUC Docket No. 34800 Order Page 3of15 SOAH Docket No. XXX-XX-XXXX 7. As provided for in Order Nos. 3, 9, 12, 14, and 23, the SOAH administrative law judges (ALJs) consolidated EGSI's appeals of the rate decisions adopted by the cities in Finding of Fact No. 6. 8. Cities participated in this case representing the Cities of Beaumont, Bridge City, Conroe, Groves, Houston, Huntsville, Navasota, Nederland, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Vidor, and West Orange. These municipalities have adopted rates consistent with the stipulation discussed below. 9. The Commission established in its Order on Appeal of Order No. 8 an effective date for EGSI's proposed rate change of September 26, 2008. 10. On April 8, 2008, the State filed a motion for partial summary decision regarding the continued applicability of the 20% base rate discount for state institutions of higher education under § 36.351 of the Public Utility Regulatory Act, TEX. UTIL. CODE ANN.§§ 11.001-66.016 (Vernon 2007 & Supp. 2008) (PURA). 11. On July 16, 2008, the SOAH ALJs issued a proposal for decision (PFD) recommending that the Commission grant the State's April 18, 2008 motion for partial summary decision. 12. On August 15, 2008, the Commission entered an order adopting the PFD on the State's motion for partial summary decision. 13. The Commission entered an order on November 4, 2008, extending the effective date ofEGSI's proposed rate change until November 27, 2008. 14. Commission Staff, State, and TIEC filed a non-unanimous stipulation (NUS) on May 19, 2008. EGSI and certain other parties filed a separate NUS on May 20, 2008. 3 The EGSI NUS was opposed by Commission Staff, State, and TIEC. A hearing was held on both NUSs on June 23 through July 2, 2008. 15. At Open Meetings on October 23 and November 5, 2008, the Commission considered a PFD from the SOAH ALJ s which recommended resolution of the rate PUC Docket No. 34800 Order Page 4of15 SOAH Docket No. XXX-XX-XXXX case through adoption of the EGSI NUS. On November 7, 2008, the Commission issued its order on remand rejecting the PFD and remanding the docket to SOAH for a hearing on the merits of EGSI's original application. 16. During the November 5, 2008 Open Meeting, EGSI agreed to extend the statutory jurisdictional deadline in this docket to March 2, 2009. EGSI subsequently agreed to extend the statutory jurisdictional deadline to March 16, 2009. 4 17. The SOAH ALJs granted ARM's motion to withdraw as an intervenor on December 2, 2008, pursuant to Order No. 49. 18. The hearing on the merits on remand took place on December 3 and 4, 2008, and December 8 through December 12, 2008. The hearing was recessed on December 12, 2008, in order to allow the parties to work on concluding a settlement. 19. On December 16, 2008, the signatories submitted a settlement term sheet to reflect their agreement in principle resolving all outstanding issues regarding EGSI's application, including those issues raised by the Commission in its November 7, 2008 order on remand. 20. On December 16, 2008, the signatories submitted an agreed motion to implement interim rates. 21. On December 19, 2008, the SOAH ALJs filed Order No. 52, granting interim approval of rates consistent with the settlement term sheet, effective with bills rendered on and after January 28, 2009, for usage on and after December 19, 2008. 22. On February 5, 2009, the signatories submitted a stipulation resolving all outstanding issues in this docket. 23. On February 10, 2009, the SOAH ALJs filed Order No. 56, returning this docket to the Commission. 3 The EGSI NUS was subsequently amended on June 27, 2008. 4 EGSI letter filed February 18, 2009. PUC Docket No. 34800 Order Page 5of15 SOAH Docket No. XXX-XX-XXXX Description of the Stipulation and Settlement Agreement 24. The signatories agree that EGSI will institute an overall mcrease in base rate revenues of $46. 7 million. 25. The signatories agree to a reasonable return on equity for EGSI of 10.00%. 26. The signatories agree that the cost of service underlying the base-rate revenue increase does not include any unreasonable or unjust expenses. 27. The signatories agree that EGSI will implement a rate-case-expense rider to recover $2.3 million per year for three years. The rate-case expenses will be allocated to customer classes based on total base-rate revenues. The rates established under the rate-case expense rider will be determined based on energy consumption in kilowatt-hours (kWh), except for the Large Industrial Power Service (LIPS) customer class, whose rates will be set on a kilowatt (kW) basis. 28. The Signatories agree to leave the mechanisms for recovery of EGSI's municipal franchise-fee riders unchanged as a result of this docket. 29. The Signatories agree that EGSl's proposed Market Value Energy Rider (MYER) will not be offered as a result of this docket. 30. The signatories agree that the Incremental Purchased Capacity Recovery Rider (IPCR) will expire contemporaneously with the implementation of rates approved in Order No. 52. 31. The signatories agree that the base-rate revenue increase, the rate-case expense rider and the municipal franchise-fee riders addressed in the stipulation became effective for bills rendered on and after January 28, 2009 for usage on and after December 19, 2008, as approved in Order No. 52. 32. The signatories reached the following specific agreements regarding rate design as a part of the overall resolution of this docket: a. Supplemental Short Term Service (SSTS). Rate Schedule SSTS will terminate six months after a final, appealable order approving the stipulation is issued by the Commission in this docket. Beginning with the PUC Docket No. 34800 Order Page 6of15 SOAH Docket No. XXX-XX-XXXX base rates implemented as a result of this stipulation, EGSI will bill SSTS usage as follows: (SSTS charges+ LIPS charges)/2. b. Interruptible Service (IS). Rate Schedule IS will be modified as follows: 1. 30-minute notice service is eliminated; ii. The credit for 5-minute notice service 1s reduced to $3.75/kW- month; 111. The credit for no-notice service is reduced to $4.88/kW-month; 1v. The credits shall be applied to the· LIPS and LIPS-Time of Use (TOU) tariffs (current High Load Factor Service (HLFS) and Large Power Service (LPS) customers will be transferred to LIPS); and v. Rate Schedule IS remains closed to new business. c. Competitive Generation Service. EGSI's competitive generation-service proposal shall not be withdrawn, but shall be severed from this docket and addr('<::<::ed in a separate docket wherein the Commission will (a) exercise its authority to approve, reject, or modify EGSI's proposal; and (b) address reCOV' • any costs unrecovered as a result of the implementation of the ,J \.J ~ 'neons Electric Service Charges. No change shall be made to Miscellaneous Electric Service Charges. e. Lighting Class Rates. Lighting-class rates for all lighting fixtures shall be designed in a manner so that each fixture is charged a uniform base-rate percentage increase as established for the entire lighting class. f. Additional Facilities Charge (AFC). Rate Schedule AFC, governing additional-facilities charge, will be designed to result in a reduction to 1.49%, with the resulting revenue reduction allocated among those customer classes with AFC revenue based on the percentage of AFC revenues in each customer class. PUC Docket No. 34800 Order Page 7of15 SOAH Docket No. XXX-XX-XXXX g. Economic as Available Power Service/Standby Maintenance Service. No substantive changes shall be made as a result of this docket to: (a) Rate Schedule EAPS, governing Economic-as-Available Power Service; or (b) Rate Schedule SMS, governing Standby Maintenance Service. h. Interconnection Terms and Conditions. No changes shall be made as a result of this docket to EGSI's terms and conditions regarding costs for interconnection of customers. L Electric Extension Policy. No changes shall be made as a result of this docket to EGSI's electric extension policy. J. Large Interruptible Power Service. The signatories stipulate that the contract demand ratchet provisions in Rate Schedule LIPS will be retained; provided, however, that the billing demand provision contained in Paragraph V of Rate Schedule SSTS will no longer apply to customers taking service under Rate Schedule LIPS after Rate Schedule SSTS terminates. 33. The signatories agree to the class-cost allocation set forth in Attachment A to the stipulation and further agree that this allocation is reasonable. 34. The signatories agree to a River Bend nuclear generating station 20-year life extension adjustment to EGSI's calculation of nuclear depreciation and decommissioning costs effective January 1, 2009. 35. The signatories agree that EGSI will reduce depreciation expense related to EGSI's steam production plants by the amount of $2,731,478 on a total Texas retail basis effective January 1, 2009. 36. The signatories agree that EGSI will present a new depreciation study as part of its next base-rate case, or by January 5, 2010, whichever is earlier. 37. The signatories agree that the base-rate increase, rate riders, and associated rate design and class-cost allocation agreed to in the stipulation are reasonable and are PUC Docket No. 34800 Order Page 8of15 SOAH Docket No. XXX-XX-XXXX reflected in the rate schedules approved by Order No. 52 and revised by errata filings on December 22, 2008, January 27, 2009, and March 5, 2009. 38. The signatories agree that EGSI will fund its Public Benefit Fund at an annualized amount of $2 million. 39. In order to include a greater portion of the eligible population in the Public Benefit Fund program, EGSI agrees to use its best efforts to contract for and implement an automatic enrollment program. EGSI's automatic enrollment program will be modeled upon the matching procedures used by other Texas utilities to identify eligible customers and will be implemented within 30 days of the Commission's filing of the final order in this case. 40. The signatories agree that EGSI will amend its low-income energy-efficiency program on a trial basis as specified in the stipulation. 41. The signatories agree that the amendment of EGSI' s low-income energy-efficiency program does not increase base rates to recover uncollected expenses associated with revenues billed under EGSI's energy-efficiency rider approved in Docket No. 35626.5 42. The signatories agree to a fuel disallowance of $4.5 million, booked in the month of a final Commission order approving the application, consistent with the stipulation. 43. The signatories agree to adopt Commission Staffs position on the following resolution of fuel-related matters set out in Commission Staffs pre-filed direct testimony: (a) recovery of sulfur dioxide (S02) and nitrous oxide (NOx) emissions revenues recorded in Account 411.8 and expenses recorded in Account 509 will be allowed as eligible fuel expense going forward until further order of the . Commission realigning such costs; (b) special circumstances should be granted to treat the costs of natural-gas call options incurred during the reconciliation period 5 Application of Entergy Texas, Inc. for Approval of an Energy Efficiency Cost Recovery Factor (EECRF) Pursuant to PURA§ 39.905(b) and P.UC. Subst. R. 25.181(/), Docket No. 35626, Order (Aug. 14, 2008). PUC Docket No. 34800 Order Page 9of15 SOAH Docket No. XXX-XX-XXXX as eligible fuel expense; (c) good cause exists to sever and defer the River Bend performance-based ratemaking (PBR) calculation for the final seven months of the reconciliation period to EGSI's next fuel reconciliation proceeding; and (d) the River Bend PBR plan should terminate in light of EGSI's jurisdictional separation. Evidence Supporting the Stipulation and Agreement 44. Considered in light of (a) the pre-filed testimony by the parties entered into evidence, and (b) the additional evidence and testimony presented by the parties during the course of the hearing on the merits on EGSI's application, the stipulation is the result of compromise from each party, and these efforts, as well as the overall result of the stipulation viewed in light of the record evidence as a whole, support the reasonableness and benefits of the terms of the stipulation. 45. The evidence addressed in finding of fact 44 demonstrates that the rates, terms, and conditions resulting from the stipulation are just and reasonable and consistent with the public interest when the merits of the issues contested by Commission Staff and intervenors are considered. 46. The stipulated revenue requirement does not include any amounts for financial- based incentive compensation. 47. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, they are reasonable and necessary for each class of affiliate costs presented in EGSI' s application. 48. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, the price charged to EGSI is not higher than the prices charged by the supplying affiliate for the same item or class of items to its other affiliates or divisions, or a non-affiliated person within the same market area or having the same market conditions. 49. The Texas retail revenue requirement in the stipulation does not include any of the following expenses, whether allocated or direct-billed to EGSI: legislative advocacy expenses; entertainment; charitable contributions; advertising expense to promote the increased consumption of electricity or to promote the image of the PUC Docket No. 34800 Order Page 10of15 SOAH Docket No. XXX-XX-XXXX electric utility industry; advertising products marketed by other affiliates; civil penalties or fines; any other expenses listed in PURA §§ 36.061, 36.062, and 36.063; payments made to cover costs of an accident, equipment failure, or negligence at a utility facility owned by a person or governmental body not selling power inside the State of Texas (except those made under an insurance or risk- sharing arrangement executed before the date of loss); the costs for processing a refund or credit under PURA § 36.11 O; any profit or loss that results from the sale of merchandise not integral to providing utility service; construction work in progress in rate base; or plant held for future use in rate base. 50. EGSI's current supplemental short-term service, Schedule SSTS, should be terminated within six months after the filing of a final, appealable Commission order in this docket, as provided for in the stipulation. 51. It is reasonable to modify EGSI's current interruptible service, Schedule IS, in accordance with the terms and conditions of the stipulation. 52. It is reasonable in light of the compromise reached in the stipulation for no substantive modifications to be made to EGSI's economic as-available power service, Schedule EAPS, or standby maintenance service, Schedule SMS. 53. The depreciation and decommissioning adjustments for nuclear production assets agreed to in the stipulation and consistent with Louisiana rate treatment are reasonable. 54. The depreciation adjustments to EGSl's steam production assets agreed to in the stipulation are reasonable. 55. The increase in storm cost accruals provided for in the stipulation is reasonable. 56. The low-income programs provided for in the stipulation are reasonable. 57. EGSI's energy-efficiency costs are recovered through a rider approved by the Commission in Docket No. 35626. 58. The PBR plan for the River Bend nuclear generating station contemplates an annual calculation of penalties and rewards. Good cause exists to sever and defer PUC Docket No. 34800 Order Page 11of15 SOAH Docket No. XXX-XX-XXXX the PBR calculation for the final seven months of the reconciliation period to EGSI's next fuel reconciliation proceeding. 59. It is reasonable to terminate the application of the PBR plan to the River Bend operations on and after January 1, 2008 when Entergy Texas, Inc. no longer has an ownership interest in River Bend. 60. EGSI is entitled to a special circumstances exception for the cost of the natural-gas call options because they resulted in increased reliability of supply and reduced fuel expense. 61. The class allocation methodologies described in the stipulation are reasonable. 62. The total level of invested capital in the Texas retail revenue requirement 1s reasonable. 63. The EGSI stipulation proposes to collect the existing incremental franchise fees of the Cities of Beaumont, Port Arthur, and Conroe as a municipal franchise-fee rider. The Commission has reviewed its finding in paragraph ILE of its remand order of November 7, 2008 and determines that the existing incremental franchise fees were the result of franchise agreements adopted subsequent to the passage of PURA § 39.456. II. Conclusions of Law 1. EGSI 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 EGSI and jurisdiction over the subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051, 36.001-36.111, 36.203, 39.452, and 39.455. 3. SOAH had 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. PUC Docket No. 34800 Order Page 12of15 SOAH Docket No. XXX-XX-XXXX 4. This docket was processed in accordance with the requirements of PURA and the Texas Administrative Procedure Act. 6 5. EGSI provided notice of its application in compliance with PURA§ 36.103, P.U.C. PROC. R. 22.5l(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3). 6. This docket contains no remaining contested issues of fact or law. 7. The stipulation, taken as a whole, is a just and reasonable resolution of all the issues it addresses, results in just and reasonable rates, terms and conditions, is supported by a preponderance of the credible evidence in the record, is consistent with the relevant provisions of PURA, and is consistent with the public interest. 8. EGSI has properly accounted for the amount of fuel and IPCR-related revenues collected pursuant to the fuel factor and Rider IPCR during the reconciliation period. 9 The revenue requirement, cost allocation, revenue distribution, and rate design implementine: the stipulation result in rates that are just and reasonable, comply •• 1~ ratemaking provisions in PURA, and are not unreasonably discriminatory, prcfrr :tial, t.. ..;ial. 1 ;~ \)ever'-' .•1 c'0SI's proposed competitive generation service into a separate ·ket :::iL ~it r, ',,,addressed separately is reasonable. EGS1 ,:. ~mi 'cd to a special circumstances exception under P.U.C. SUBST. R. 25.236(a)(6) for :he cost of natural gas call options. 12. Consistent with the stipulation, good cause exists to treat EGSl's emissions revenues and expenses referenced in finding of fact 43 as eligible fuel expense on a going-forward basis until further order of the Commission realigning such costs. 13. Based on the evidence in this docket, the overall total invested capital through the end of the test year meets the requirement in 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. 6 TEX. GOV'T. CODE ANN. Chapter 2001(Vernon2000 and Supp. 2007). PUC Docket No. 34800 Order Page 13of15 SOAH Docket No. XXX-XX-XXXX 14. The Commission has reviewed its finding in paragraph ILE of its remand order of November 7, 2008 and determines that because the existing incremental franchise fees were the result of franchise agreements subsequent to the passage of PURA § 39.456, they qualify as new franchise agreements and are therefore in compliance with PURA§ 39.456 when recovered as a municipal franchise-fee rider. 15. The final resolution of the instant docket does not impose any conditions, obligations, or limitations on EGSI's right to file a base-rate proceeding and obtain rate relief in accordance with PURA. 16. Consistent with the stipulation, EGSI has met its burden of proof in demonstrating that it is entitled to the agreed upon level of Texas retail base-rate and rider revenue. 17. Consistent with the stipulation and PURA, EGSI has met its burden of proof in demonstrating that the rates are just and reasonable. III. Ordering Paragraphs In accordance with these findings of fact and conclusions of law, the Commission issues the following orders: 1. Consistent with the stipulation, EGSI's application for authority to (a) change its rates; (b) reconcile its fuel and purchased power costs for the Reconciliation Period from January 1, 2006 to March 31, 2007, as well as deferred costs from prior proceedings; and (c) for other related relief is approved. 2. Consistent with the stipulation, the rates, terms, and conditions described in this order are approved. 3. Consistent with the stipulation, the tariffs and riders approved on an interim basis by Order No. 52 and revised by errata on December 22, 2008, January 27, 2009, and March 5, 2009, are approved. PUC Docket No. 34800 Order Page 14of15 SOAH Docket No. XXX-XX-XXXX 4. Consistent with the stipulation, EGSI shall implement the low-income programs described in this order. 5. Consistent with the stipulation, EGSI's Competitive Generation Services tariff is severed from this docket and shall be addressed in Application of Entergy Texas, Inc.for Approval of Competitive Generation Services Tariff, Docket No. 36713. 6. Consistent with the stipulation, EGSI's storm-cost accruals shall be increased by $2 million for a total accrual of $3.65 million annually beginning January l, 2009, which amount will be incorporated in revenues recovered through base rates. 7. Consistent with the stipulation, EGSI shall terminate rate schedule SSTS and Rider IPCR. 8. Consistent with the stipulation, EGSI shall adjust depreciation and decommissioning expense related to the River Bend nuclear generating station and depreciation expense related to EGSI's steam production assets. 9. Consistent with the stipulation, EGSI shall submit a new depreciation study. 10. Consistent with the stipulation, the Rider IPCR and fuel costs, including coal- related costs deferred from prior proceedings are reconciled and approved through March 31, 2007. 11. EGSI shall adjust its fuel over/under recovery balance consistent with the findings in this order. 12. The entry of this order consistent with the stipulation does not indicate the Commission's endorsement of any principle or methodology that may underlie the stipulation. Neither should entry of this order be regarded as precedent as to the appropriateness of any principle or methodology underlying the stipulation. 13. 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. PUC Docket No. 34800 Order Page 15of15 SOAH Docket No. XXX-XX-XXXX SIGNED AT AUSTIN, TEXAS the _ _ day of March 2009 PUBLIC UTILITY COMMISSION OF TEXAS ~ /. B ITHERMAN, CHAIRMAN DONNA L. NELSON, COMMISSIONER q.\cadm\orders\final\34000\34800fo2.doc Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 2009 WL 4724725 (Tex.P.U.C.) Slip Copy Application of Oncor Electric Delivery Company, LLC for Authority to Change Rates 35717 XXX-XX-XXXX Texas Public Utility Commission November 30, 2009 ORDER ON REHEARING Before Smitherman, Chairman, Nelson and Anderson, Jr., Commissioners. BY THE COMMISSION: This Order addresses the application of Oncor Electric Delivery Company, LLC for authority to change its rates. On June 27, 2008, Oncor filed its first application with the Public Utility Commission of Texas for a rate change since it was unbundled on January 1, 2002. Oncor originally requested a total net increase of $275 million, of which $45 million represented the net increase associated with transmission service, and $230 million represented the net increase associated with the retail delivery service. Oncor revised its revenue requirements on August 11, 2008, in its 45-day update to the rate filing package. 1 As updated, Oncor's system-wide adjusted rate increase would yield $253,468,000 of increased revenue. On June 2, 2009, 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 Oncor of $30,274,392. The Commission adopts in part and rejects in part the proposal for decision issued by the ALJs in this proceeding, including the findings of fact and conclusions of law. For the reasons discussed in this Order, the Commission determines that Oncor's appropriate system-wide adjusted rates will lead to a revenue increase of $115,061,510. 2 I. PROCEDURAL HISTORY Oncor filed its petition and rate filing package on June 27, 2008. On July 1, 2008, the Commission referred this case to SOAH. An order was issued suspending the effective date of tariff changes and setting a prehearing conference. On August 6, 2008, the Commission filed a preliminary order listing the issues to be addressed in this proceeding. On November 20, 2008, Oncor requested that the issues concerning the costs incurred in presenting this rate case be moved to a separate docket. The matter was severed into Application of Oncor Electric Delivery Company, LLC for Rate Case Expenses Pertaining to Docket No. 35717, Docket No. 36530. The hearing on the merits convened before SOAH ALJs Henry Card and Catherine Egan on January 13, 2009, and continued until February 9, 2009. At the close of the evidentiary hearing, Oncor announced on the record that it agreed to extend the jurisdictional deadline to July 15, 2009. 3 The record remained open for the filing of briefs. On March 27, 2009, the parties filed their reply briefs and the record closed. Number running began on May 12, 2009 with Staff returning the final numbers to the ALJs on May 22, 2009. The parties requested that the ALJs file the PFD by June 2, 2009. Exceptions to the PFD and replies to exceptions were filed. Subsequently, on July 1, 2009, the ALJs filed a letter recommending changes to certain findings of fact. Accordingly, findings of fact 8, 15, 24, 41, 43, 49, 51, 118, 119, and 203 are modified to reflect the recommendations made by the SOAH ALJs. Finding of fact 14 is not modified in response to the ALJs' letter because, as discussed below, this finding is deleted in accordance with Chairman Smitherman's memorandum responding to motions for rehearing. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 1 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... The Commission considered this matter at six Open Meetings: July 2, 2009, July 30, 2009, August 13, 2009, October 8, 2009, October 22, 2009, and November 5, 2009. At the July 2, 2009 Open Meeting, Oncor agreed to extend the jurisdictional deadline to August 31, 2009. Oncor implemented its new rates on September 17, 2009 based on the Commission's August 31, 2009 Order. Motions for rehearing were filed by the State of Texas, Oncor Delivery Company, LLC., Alliance of TXU/Oncor Customers, Office of Public Utility Counsel, Steering Committee of Cities, Texas Industrial Energy Consumers, on September 21, 2009. Commission Staff and Texas Industrial Energy Consumers filed responses to the motions for rehearing on September 30, 2009. On October 8, 2009, the Commission issued an order extending time to act on motions for rehearing to the maximum time allow by law. At the October 22, 2009 Open Meeting, the Commission raised the issue of what applicability, if any, does the Texas Supreme Court's holding in Suburban Utility Corporation v. Public Utility Commission of Texas 4 have on the federal income tax issues in this proceeding. The Suburban court held that a subchapter S corporation 5 “is entitled to a reasonable cost of service allowance for federal income taxes actually paid by its shareholders on [the utility's] taxable income or for taxes it would be required to pay as a conventional corporation, whichever is less.” 6 The Commission requested briefing on the Suburban case in its October 22, 2009 Open Meeting and a briefing order was issued that day. Responses were filed October 29, 2009 and the Commission addressed the issue during its November 5, 2009 Open Meeting. New findings of fact 35B, 35C, and 35D are added to reflect this additional procedural history. Additionally, Chairman Smitherman filed a memorandum on October 22, 2009 wherein he proposed twelve modifications in response to Oncor's motion for rehearing. These modification are adopted by the Commission. Accordingly, findings of fact 14, 35, 36, 66, 70, 112, 133, and 134 are deleted and replaced with new findings of fact 14A, 35A, 36A, 66A, 70A, 112A, 133A, and 134A; and ordering paragraph 7 is modified to properly reflect or clarify the Commission's decision as discussed in the Chairman's memorandum. New findings of fact 128B and 174A and new conclusion of law 19B are discussed later in this Order. II. DISCUSSION A. Cash Working Capital (CWC) The Commission disagrees with the ALJs' finding that Oncor's requested cash working capital (CWC) should be reduced by $2,453,665 to remove Oncor's allowance for expenses covering employee home-purchase plans and employee home loans for the purchase of energy-efficiency items and appliances. The Commission agrees with Oncor's position that P.U.C. SUBST. R. § 25.231(c)(2)(B)(iii)(IV)(e) specifically provides that working cash funds like those Oncor proposed should be included in the CWC calculations. 7 The Commission further agrees that Oncor's overall level of employee compensation, including employee benefits, is designed to be competitive and is reasonable and necessary to allow the Company to attract qualified and experienced personnel required to provide safe and reliable electric service. 8 The Commission finds that the expenses are reasonable and necessary and that Oncor should have the discretion to offer these options as part of the compensation program for Oncor employees. The Commission therefore reverses the recommendation in the PFD 9 and allows Oncor to recover the $2,453,665 in its CWC allowance. Finding of fact 71 is deleted and new finding of fact 71A is added to reflect the Commission's decision. B. Plant Held for Future Use (PHFU) © 2015 Thomson Reuters. No claim to original U.S. Government Works. 2 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... The ALJs found that Oncor's proposed plant held for future use (PHFU) should be reduced by $12,639,442 because Oncor has not provided a credible plan that the properties are going to be placed in service within ten years. The Commission disagrees. Oncor requested a PHFU level of $17,110,015. The Alliance of TXU/Oncor customers (ATOC) contested this number and identified several parcels totaling $12,639,442 that should be removed from the PHFU because they had continuously moving in-service dates. The Commission finds that Oncor presented a credible plan for these parcels and that companies that are in Oncor's position need to have flexibility to move items in and out of their plans. Findings of fact 73 and 74 are deleted and new findings of fact 73A, 73B and 74A are added to reflect the Commission's decision. C. Capgemini Energy (CGE) Charges to Oncor The ALJs recommended the disallowance of $5,673,205.90 in Capgemini Energy (CGE) charges to Oncor based on the determination that there was a “possibility that the $88 million included some disputed charges,” and the concern that Oncor did not prove the reasonableness of additional resource charges (ARC) representing that amount. The Commission reverses the PFD to modify the amount disallowed to $1,433,094.47. The Commission is persuaded by Oncor's arguments that the disallowed $5,673,205.90 was based on the ALJs' incorrect determination of the record. The Commission agrees with Oncor that there is no record evidence to support the conclusion that the disallowed $5,673,205.90 represented disputed charges. The $1,433,094.47 reflects Oncor's acknowledgement that it was credited $16,008,942.33 in the separation agreement with CGE for disputed and undisputed charges and that the $1,433,094.47 disallowance is Oncor's estimate of the amount of CGE charges that should be disallowed associated with the test-year. 10 Finding of fact 111 is deleted and new finding of fact 111A is added to reflect the Commission decision to modify the disallowed amount. D. Account Code 365 - Distribution Overhead Conductor On the issue of net salvage value for Account 365, Distribution Overhead Conductors, the ALJs found the preponderance of the evidence supports that a negative 40% net salvage rate would be appropriate as argued by ATOC. Oncor argued that because the average net salvage value for the last 10 years was negative 54%, a negative 55% net salvage was appropriate as a conservative estimate of the ongoing removal cost in this account. 11 Commission Staff advocated a negative 53% net salvage based on a gross salvage of 5% and cost of removal of 58% for 1998 through 2007. 12 ATOC also noted that Oncor had experienced three or four of the worst storms in its history between 2004 and 2007, which would have driven up the cost of removal. The Commission finds that the preponderance of the evidence weighs in favor of the net salvage values of negative 54% as proposed by both Oncor and Commission Staff and reverses the PFD on this point. Finding of fact 124 is deleted and new finding of fact 124A is added to reflect the Commission's decision. E. Suburban Holding In Suburban Utility Corporation v. Public Utility Commission of Texas, 13 the Texas Supreme Court held that Suburban Utility, a subchapter S corporation, 14 “is entitled to a reasonable cost of service allowance for federal income taxes actually paid by its shareholders on [the utility's] taxable income or for taxes it would be required to pay as a conventional corporation, whichever is less.” 15 Oncor argued that because the actual taxes-paid doctrine was subsequently disavowed by the supreme court, 16 the only viable portion of the Suburban holding required that its tax expense be calculated as if it were a conventional corporation. 17 All the other parties argued that the holding in Suburban was still valid and requires that Oncor's tax expense be based on the actual tax expense paid by Oncor's shareholders. 18 © 2015 Thomson Reuters. No claim to original U.S. Government Works. 3 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... The Commission agrees with the supreme court that there is no such thing as actual taxes in a ratemaking proceeding. 19 As the court noted, rates are based on historic test-year amounts, but those amounts are adjusted and modified during the rate setting process, or are based on assumptions. 20 In addition, although not mentioned by the court, the amount of income tax expense as typically calculated is directly related to the return on equity set by the Commission, a return that the utility will almost certainly never obtain-either missing it on the high side or the low side. Thus, “[t]he income tax calculation is no different than other elements of utility ratemaking.” 21 In setting rates, the Commission has considerable discretion. Consequently, the Commission concludes that, under Suburban, it must make an allowance for taxes but that, under GTE- Southwest and subsequent cases, it has discretion to determine the appropriate method and amount. The Commission recognizes that PURA limits its discretion. For example, the Commission cannot consider disallowed expenses in setting rates; 22 the rates it sets must be just and reasonable, 23 but cannot be unreasonably preferential or discriminatory; 24 and the rates must provide “overall revenues . . . that will permit the utility a reasonable opportunity to earn a reasonable return on the utility's invested capital .. . in excess of the utility's reasonable and necessary operating expenses.” 25 Even with these statutory limitations, the Commission has considerable discretion. Oncor is a limited liability corporation (LLC) organized under Delaware law. It is taxed as a partnership under federal law and is therefore not currently eligible to file a consolidated tax return with Energy Future Holdings (EFH). 26 Additionally, the Commission determines Oncor's status to be that of a ring-fenced utility that has entered into a tax sharing agreement with EFH and its affiliates that requires Oncor to function as a stand-alone company. The tax sharing agreement was created in October 2007 in an effort to insulate Oncor from the liability related to EFH and its affiliates. The Commission concludes that Oncor should be treated as a stand-alone company. Because the Commission determines that Oncor should be treated as a stand-alone and ring-fenced company, the Commission concludes that Oncor's tax expense should be calculated as if it were a conventional corporation. This treatment will afford Oncor with a reasonable amount for tax expense, including federal income tax and other state taxes. Further, while the record is not fully developed on this point, it appears that the amount allowed for federal income tax expense would not differ greatly from the expense that would be allowed using the tax rates of Oncor's shareholders considering only the income and expenses resulting from Oncor's operation as a utility. 27 Even though the tax expense allowed by the Commission will not differ in amount from the amount requested by Oncor under its tax-sharing agreement, the Commission emphasizes that it is not basing its decision on the tax-sharing agreement between Oncor and Energy Future Holdings Corporation (EFH). The Commission has never been expressly asked to consider and approve that agreement, it has not previously approved that agreement, and it is not doing so here. While this agreement provides some benefits to isolate Oncor from its shareholders, neither Oncor nor any other utility can bind the Commission to establish a tax expense in a rate proceeding through a bilateral contract that has not been approved by the Commission. . F. Consolidated Tax Savings Adjustment (CTSA) The Commission reverses the ALJs' determination that it was appropriate for Oncor to include a consolidated tax savings adjustment (CTSA) in its federal income tax expense calculations. The Commission is required-unless it is shown to be reasonable not to do so-to calculate a utility's income tax expense “as though a consolidated return had been filed and the utility had realized its fair share of the savings resulting from that return, if:” (1) the utility is a member of an affiliated group eligible to file a consolidated return; and (2) it is advantageous for the utility to do so. 28 The Commission finds that Oncor is not currently a member of an affiliated group eligible to file a consolidated tax return; and therefore, the provisions of PURA § 36.060 do not apply to it. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 4 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... The Commission's CTSA decision in this proceeding is not based on Oncor's tax-sharing agreement with EFH and its affiliates. Rather, it is limited to the Commission's determination that the statutory requirements to include a CTSA are not met. To reflect the Commission's decisions regarding tax expenses, finding of fact 128 is deleted and new findings of fact 128A-F are added. Findings of fact 129 and 130 are deleted consistent with the Commission's finding that a consolidated tax savings adjustment is not applicable to Oncor. Additionally, conclusion of law 19 was deleted and replaced with new conclusions of law 19A-D to reflect the Commission's legal conclusion on this point. G. State and Local Taxes - Texas Gross Margin Tax The Commission reverses the ALJs determination that Oncor must compute its gross margin tax as an affiliate. Consistent with the Commission's decision regarding taxes, the Commission finds that Oncor is not a member of an affiliated group and Oncor should calculate its Texas gross margin tax on a stand-alone. Further, the Commission notes that its decision is not based on the tax-sharing agreement. To reflect the Commission's decision on the Texas gross margin tax issue, finding of fact 132 is deleted and new finding of fact 132A is added. H. State and Local Taxes - Municipal Franchise Fees The Commission disagrees with the ALJs' interpretation of PURA § 33.008 and reverses the ALJs' findings and conclusions regarding municipal franchise fees. Oncor requested recovery of municipal franchise fees totaling $253,884,976. Commission Staff challenged this amount and recommended a reduction of $5,696,931. 29 According to Commission Staff, Oncor is not entitled to recover the 5% increase in the franchise fee rate that it agreed to pay pursuant to an agreement with Cities. 30 The Commission agrees with Commission Staff's interpretation that PURA § 33.008(b) specifies how to calculate municipal franchise fees owed by a utility to municipalities within its service territory. 31 Since Oncor agreed to pay its municipalities 5% more than the 2005 effective rate calculated pursuant to PURA § 33.008(b), it is not an expense that is reasonable and necessary to provide service to the public. 32 The Commission also notes its concern over allowing ratepayers who reside outside of the Cities' jurisdiction to pay for franchise fees calculated in an agreement to which their city or municipality was not a party. Finding of fact 133 is deleted and new finding of fact 133A is added to reflect the Commission's decisions regarding municipal franchise fees. I. Automated Meter Recovery Regarding the issue of automated meter recovery, the ALJs determined that 41.82% of Oncor's investment in automated meters should not be recovered. Oncor requested the inclusion of $93,185,786.07 in plant-in-service for its powerline carrier (PLC) and broadband-over-powerline carrier (BPL) meters. Commission Staff, ATOC, and Cities argued that Oncor's purchase and installation of automated meters between 2004 and the adoption of the advanced metering system (AMS) rule on May 30, 2007 was partly or entirely imprudent, and recommended disallowing all or part of that investment. Oncor pointed to national and state legislative initiatives that Oncor believed supported and encouraged its deployment of advanced metering systems and Oncor's continued deployment of its PBL and PLC meters. 33 Additionally, Oncor cited a discussion among Commissioners Hudson, Parsley, and Smitherman at the Commission's May 8, 2007 Open Meeting in which the Commissioners strongly encouraged the deployment of BPL meters. 34 The Commission agrees with Oncor's position and finds that Oncor did have significant encouragement from the Commission in deploying both PLC and BPL meters. The © 2015 Thomson Reuters. No claim to original U.S. Government Works. 5 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... Commission further finds that Oncor acted prudently and in accordance with the information they had at the time. Therefore, the Commission allows Oncor to recover the full costs of its BPL and PLC meters. To give effect to the Commission's decisions regarding automated metering, findings of fact 141, 144, 145, 147, 149, 150, 151, 152 and 153 are deleted and new findings of fact 141A, 153A, and 153B are added. Additionally, conclusion of law 21 is deleted and new conclusion of law 21A is added to reflect the Commission's legal conclusion regarding the prudence standard set out in Application of Gulf States Utilities for Authority to Change Rates, Docket No. 6525 (Oct. 15, 1986). J. Creation of Primary Substation Rate Class The Commission disagrees with the ALJs' recommendation to deny Oncor's request to create a new primary substation rate class 35 and approves the creation of a new primary-greater-than-10-kW substation tariff. This new service affects about 50 primary substation customers, mostly industrial customers, receiving voltage from, or near, a substation. These customers construct and maintain the distribution facilities themselves. The only distribution facilities required by Oncor to provide this service are the distribution substation facilities. Additionally, the service is virtually identical to the service provided to current wholesale customers from Oncor's existing XMFR tariff. The Commission notes that Oncor implemented its current rates on September 17, 2009. Those rates reflect the Commission's August 31, 2009 Order which did not provide for the primary-greater- than-10-kW substation tariff. Therefore, rate adjustments required to reflect the Commission's decision on rehearing shall be prospective from the date of the final order in this proceeding. Findings of fact 155, 156 157, 158, 159, and 160 are deleted and new findings of fact 155A, 156A, 157A, 158A, 159A, 160A, and 160B are added to reflect the Commission's decisions regarding the creation of a new primary substation rate class. K. Cost Allocation - Direct Assignment of Cost to Wholesale Customers The PFD indicates that Oncor should maintain data adequate for the direct assignment of costs to those wholesale classes and to prepare a cost-of-service study using direct assignment for those classes in its next rate case. 36 The Commission clarifies this point so as to order Oncor to maintain data adequate for direct assignment of costs to wholesale classes. However, the Commission believes that the direct assignment of such costs should be conducted in a broader forum than a rate-setting proceeding. Findings of fact 173 and 174 are deleted and replaced with new findings of fact 173A and 174A to clarify the Commission's position regarding direct assignment of costs to wholesale classes of customers. In addition to the changes addressed above, the Commission notes that other minor, non-substantive corrections and modifications to the ALJs' proposed findings of fact and conclusions of law were made. III. FINDINGS OF FACT Introduction and Procedural History 1. Oncor Electric Delivery Company, LLC (Oncor), formerly TXU Electric Delivery Company, is an investor-owned electric utility within the Electric Reliability Council of Texas (ERCOT) system. 2. Oncor provides transmission and distribution electrical services in the northeast to central and west Texas, including the Dallas-Fort Worth Metroplex area. Oncor delivers electricity to three million meters that reach close to seven million consumers in 401 cities and 91 counties in Texas. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 6 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 3. Oncor is the largest transmission and distribution utility (T&D) company in Texas and is the sixth largest T&D in the United States. 4. As part of the unbundling cost of service hearings, in 2001, Oncor's costs of services were separated for accounting purposes between its transmission and distribution functions and its rates were set among various classifications. 5. On February 25, 2007, Oncor's former parent company, TXU Corp., entered into an Agreement and Plan of Merger with Texas Energy Future Holding Limited Partnership (TEF) and Texas Energy Merger Sub Corp (Merger Sub) (the merger agreement). 6. Pursuant to the merger agreement, TEF acquired TXU Corp and changed TXU Corp.'s name to Energy Future Holdings Corporation (EFH). 7. Oncor became a wholly owned subsidiary of Oncor Electric Delivery Holdings Company LLC, which is a member of the EFH system of companies. 8. On October 10, 2007, Oncor entered into a tax sharing agreement (the tax sharing agreement) with EFH in an effort to insulate Oncor from the liabilities related to EFH and its affiliates. 9. The tax sharing agreement benefits both Oncor's shareholders and ratepayers. 10. The Commission approved the merger agreement in Joint Report and Application of Oncor Electric Delivery Company and Texas Energy Future Holding Limited Partnership Pursuant to PURA 14.101, Docket No. 34077 (April 24, 2008). 11. On November 5, 2008, EFH sold 19.95% of Oncor to investors from Canada and Singapore for $1,254,000,000. 12. In 2008, Oncor became a Delaware Limited Liability Corporation. 13. On June 27, 2008, Oncor filed its application with the Public Utility Commission of Texas for authority to increase its transmission and distribution rates to achieve an increase in revenue of approximately $275 million. 14. DELETED. 14A. Oncor revised its proposed revenue requirements in its 45-day update to the rate filing package (August 11, 2008), its Supplemental Direct Testimony (October 3, 2008), it's Rebuttal Testimony (December 23, 2008) and its Omnibus errata Filing (January 9, 2009), and is now requesting increased revenue of approximately $253,468,000. 15. Of this amount, retail distribution service revenues would increase approximately $210,000,000, and transmission revenues would increase approximately $44,000,000. 16. Concurrent with its filing with the Commission, Oncor filed a similar petition and statement of intent with each incorporated city in its service area that has original jurisdiction over its retail rates. 17. Oncor provided notice by publication once a week for four consecutive weeks before the effective date of the proposed rate change in newspapers having general circulation in each county in Oncor's service territory. 18. Individual notice of Oncor's application was provided to the Commission Staff and the Office of Public Utility Counsel on June 27, 2008. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 7 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 19. On June 27, 2008, Oncor sent a copy of its petition and statement of intent by hand-delivery to each municipality within Oncor's service area with original jurisdiction. 20. Oncor timely served notice by either hand-delivery or over-night delivery of its complete rate filing package and compact disc to all authorized representatives of the parties in Petition by Commission Staff for a Review of the Rates of TXU Electric Delivery Company, Docket No. 34040 (June 30, 2008). 21. On June 27, 2008, Oncor mailed notice of its petition and statement of intent to all authorized representatives of the parties in Joint Report and Application of Oncor Electric Delivery Company and Texas Energy Future Holdings Limited Partnership Pursuant to PURA § 14.101, Docket No. 34077 (April 24, 2008). 22. On June 27, 2008, Oncor mailed notice of its petition and statement of intent to all Retail Electric Providers (REPs) who have been certified by the Commission and who serve end-use customers in Oncor's service area and to all entities listed in the Commission's transmission matrix in Docket No. 35011. 23. The Commission referred this proceeding to SOAH on July 1, 2008. On August 6, 2008, the Commission issued its preliminary order setting forth the issues to be addressed in this proceeding. 24. The following entities were granted intervenor status in this case: Alliance of TXU/Oncor Customers (ATOC); Steering Committee of Cities (Cities); International Brotherhood of Electrical Workers Local 69 (IBEW); Lee Smith; Alliance for Retail Markets (ARM); Texas Industrial Energy Consumers (TIEC); Denton Municipal Electric; State of Texas; Occidental Power Marketing, L.P.; Office of Public Utility Counsel; Texas Association for Marketers (TEAM); Tex-La Electric Cooperative of Texas, Inc.; Rayburn Country Electric Cooperative; City of Garland; Texas Legal Services Corporation/Texas Ratepayers Organization to Save Energy (TLSC/TxRose); TXU Energy Retail; Kroger Company; Reliant Energy Retail Services, LLC; Nucor Steel-Texas (Nucor); Environmental Defense Fund (EDF); the Commercial Group; and Centerpoint Energy Houston. 25. Oncor timely filed appeals with the Commission of the rate ordinances of the municipalities exercising original jurisdiction within its service territory. All such appeals were consolidated for determination in this proceeding. 26. On September 11, 2008, State moved for partial summary disposition regarding Oncor's request to modify its base rate discount for state institutions of higher learning. 27. The Administrative Law Judge (ALJ) issued a proposal for decision addressing State's motion for partial summary disposition on November 13, 2008, recommending that the Commission grant State's motion. 28. On January 30, 2009, the Commission partially rejected the ALJ's recommendation and issued an Order ruling against State finding also that Oncor was not allowed to provide the 20% discount to institutions of higher education at the expense of ratepayers. 29. On February 17, 2009, State filed a request to reconsider the order with the Commission. 30. Commission Advising and Docket Management refused to ballot the Commissioners on State's motion because State's request for reconsideration was untimely filed. 31. State filed a motion for leave to late file its motion for reconsideration on February 17, 2009. The Commissioners voted not to hear State's motion. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 8 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 32. On January 2, 2009, Oncor's request that its rate case expenses be severed from this docket was granted. The severed matter was assigned Application of Oncor Electric Delivery Company LLC for Rate Case Expenses Pertaining to PUC Docket No. 35717, Docket No. 36530. 33. Oncor's application is based on the test year ending December 31, 2007. 34. The hearing on the merits began on January 13, 2009, and lasted seventeen hearing days, concluding on February 9, 2009. 35. DELETED. 35A. Oncor's proposed effective date for the proposed rates was suspended by the SOAH ALJs for 150 days. Oncor agreed to further extend the effective date for its proposed rates until July 15, 2009, and then again until August 31, 2009, to allow sufficient time for the ALJs and the Commission to process the case. 35B. Oncor implemented its new rates on September 17, 2009, based on the Commission's August 31, 2009, Final Order. 35C. Motions for rehearing were filed on September 21, 2009, and on October 8, 2009, the Commission issued an order extending time to act on motions for rehearing to the maximum time allow by law. 35D. The Commission issued an order requesting briefings on the Suburban case after the October 22, 2009 Open Meeting, and subsequent to receiving responses from the parties, considered the issue in the November 5, 2009 open meeting. Rate Base 36. DELETED. 36A. Oncor's T&D capital investments in the amount of $7,881,760,603 net plant in service (including investments currently being recovered through Oncor's transmission cost of service), were used and useful, and reasonable and necessary, and should be approved. 37. Accumulated Deferred Federal Income Taxes (ADFIT) represent a timing difference in the amortization or depreciation of an asset that differs from the tax amortization or depreciation. 38. ADFIT operates as a reduction to the rate base, or invested capital, upon which the rate of return may be applied. 39. Oncor withdrew its proposed adjustment to ADFIT for liberalized depreciation expenses. 40. Oncor's ADFIT amounts should be adjusted to increase Oncor's ADFIT by $50,228,784 to reverse Oncor's reduction to the ADFIT for liberalized depreciation. 41. Oncor's ADFIT includes a $43,539,628 deferred tax asset for its current and non-current alternative minimum tax (AMT) credits, thereby increasing the rate base. 42. To ensure that some federal income taxes are paid each year, federal income tax (FIT) returns must be calculated two ways each year, the regular tax return method and the AMT method. 43. The current income tax is paid based on the taxing method (regular tax or AMT) that yields the highest tax liability. Taxes paid on an AMT basis generate AMT credits that can be used to offset future regular taxable liability. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 9 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 44. During the test year, Oncor did not file its own tax return, but instead prepared its FIT records and forwarded them to EFH, the holding company, and EFH filed a consolidated tax return. 45. The EFH consolidated group had to file its tax returns under the AMT method from 1992 to 2008 causing Oncor's AMT credits to accumulate. 46. As a result of the tax savings agreement entered into on October 10, 2007, Oncor prepared and calculated its FIT return as though it is a stand-alone corporation. 47. Unless expressly provided for in PURA, the Commission rules, or approved in a Commission order, agreements between a regulated utility and its parent company do not alone dictate how rates are set. 48. Oncor's tax sharing agreement is not binding on the Commission. 49. Ratepayers paid Oncor's FIT expenses calculated at the regular tax rate irrespective of how Oncor, or EFH, actually paid the IRS and irrespective of what tax method was used by EFH to calculate the taxes. 50. FIT expenses must be normalized so that the tax effects of income and expenses are recognized at the same time that the related income and expenses are incurred. 51. AMT credits (deferred tax asset) represent a prepayment of regular federal income taxes. 52. The accumulated AMT credits represent a cost to Oncor for its participation in the EFH consolidated group that should not be charged to the ratepayers. 53. Oncor's AMT credits totaling $43,539,628 should be removed from its ADFIT balance. 54. In June 2006, the Financial Accounting Standard Board (FASB) issued Financial Interpretation 48 (FIN 48), “Accounting for Uncertainty in Income Taxes,” requiring companies to identify each uncertain tax position by evaluating the tax position on its technical merits to determine whether the tax position, and the corresponding deduction, is more-likely-than not to be sustained by the Internal Revenue Service (IRS). 55. FIN 48 became effective on January 1, 2007, and requires companies with uncertain tax positions to remove the amount from the ADFIT and record it as a potential liability with interest to better reflect the company's financial condition. 56. During the test year, Oncor conducted a FIN 48 analysis and determined that $96,972,460 did not meet the FIN 48 standard. Oncor reclassified the tax benefit from an ADFIT to a non-current reserve that accrues the IRS prescribed interest. 57. The Commission requires a utility to use the Federal Energy Regulatory Commission (FERC) chart of accounts in preparing its rate filing package. 58. Recognizing the competing needs between financial reporting unrelated to ratemaking, and reporting for ratemaking, FERC issued a policy statement in May 2007 stating that utilities are not to follow FIN 48 for financial accounting and reporting submitted to FERC. 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. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 10 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 60. Oncor may not have to pay the IRS the FIN 48 deductions of $96,972,460; and therefore, they should be added back into the ADFIT for ratemaking purposes. 61. Oncor properly included its ADFIT assets for pension, other postemployment benefits (OPEBs), and FAS 112 liabilities in its ADFIT balance. 62. Investor-owned electric utilities may include a reasonable allowance for cash working capital (CWC) in the rate base as determined by a lead-lag study conducted in accordance with the Commission's rules. 63. In Oncor's last rate case, the Commission approved CWC of a negative $73,955,000. In this rate case, Oncor requested a positive CWC allowance of $1,370,010. 64. CWC 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. 65. Oncor's calculation of its lead days for vegetation management (a positive 123.22) was unreasonable in that Oncor estimated that the service period for tree trimming and other vegetation management extended a year beyond when the trees were trimmed. 66. DELETED. 66A. The service period for non-labor, other-third-party expenses is the actual period in which the services are provided and therefore Oncor's expense lead days for vegetation management should be a negative 36.02. 67. Oncor's CWC for vegetation management expenses is $1,163,317, not the $12,397,196 requested. 68. Oncor's request for a negative 11.75 lead days for its pension expenses is reasonable. 69. Oncor's payment of the invoice for a year-long meter maintenance contract was not a prepayment and was properly included in Oncor's CWC allowance. 70. DELETED. 70A. Commission Staff's recommendation regarding the calculation of lead days related to the State Gross Margin Tax should be adopted and the amount of lead days should be changed from Oncor's proposed positive 46.42 days to a negative 319.58 lead days. 71. DELETED. 71A. Oncor's inclusion of $2,453,665 in its CWC allowance for expenses covering employee home purchase plans and employee loans for the purchase of energy-efficiency items and appliances is reasonable and should be approved. 72. Oncor's decision to withdraw from the accounts receivable financing program was financially reasonable and in the best interest of the ratepayers. 73. DELETED. 73A. Oncor's plant held for future use (PHFU) proposed in its rate base included PHFUs for which Oncor had a credible plan for use within a ten-year period. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 11 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 73B. Companies in Oncor's position need to have flexibility to move items in and out of their plans. 74. DELETED. 74A. Oncor's proposed PHFU level of $17,110,015 is reasonable and should be granted. 75. Oncor included in its regulatory assets $20,274,840.00, the costs it incurred in restructuring efforts undertaken in 2004 and 2006 to reduce labor and related costs, and requested that it be amortized over a five-year period, $4,054,968 per year. 76. While Oncor's restructurings efforts may have reduced its O&M expenses and capital spending, Oncor did not use these savings to defray costs associated with the restructuring. 77. Oncor's restructuring expenses were not incurred in the test year, were not authorized by PURA or a Commission rule or preapproved by the Commission, and the recovery of which were not shown to be essential to its financial integrity. 78. Oncor's restructuring expenses undertaken in 2004 and 2006 to reduce labor and related costs in the amount of $20,274,840 are not regulatory assets and should not be included in Oncor's rate base. 79. Oncor's request to include in its rate base as regulatory assets $46,975,122 for deferred pension costs and $37,906,425 for deferred OPEB costs was reasonable and should be adopted. 80. Oncor properly included $50,809,942 as the cost of materials and supplies in its rate base. 81. Oncor's prepayments of $79,974,656 were reasonable and should be included in its rate base. Return on Equity and Capital Structure 82. A return of equity of 10.25% will allow Oncor a reasonable opportunity to earn a reasonable return on its capital investment. 83. Oncor's energy conservation efforts, the quality of its services, the efficiency of its operations, and the quality of its management support a 10.25% return on equity. 84. A reasonable application of the discounted case flow model, capital asset pricing model, risk premium study, and comparable earnings study support a return on equity of 10.25%. 85. A 10.25% return on equity is consistent with the level of financial risk associated with Oncor's capital structure. 86. Oncor's revised cost of debt, 6.97%, is reasonable. 87. The appropriate capital structure for Oncor is 60% long-term debt and 40% common equity. 88. Oncor has used this capital structure since 2002. 89. The capital structure of 60% and 40% is consistent with Commission precedent for T&D utilities. 90. Oncor's overall rate of return is as follows: © 2015 Thomson Reuters. No claim to original U.S. Government Works. 12 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... COMPONENT CAPITAL STRUCTURE COST OF CAPITAL WEIGHTED AVG COST OF CAPITAL LONG-TERM CAPITAL 60.00% 6.97% 4.18% COMMON EQUITY 40.00% 10.25% 4.10% TOTAL 100.00% 8.28% Cost of Service 91. Oncor included in its cost of service $19,573,479 for incentive compensation paid to its employees in the test year. 92. Incentive compensation based on financial measures or goals is of more immediate benefit to shareholders. 93. Of the amount Oncor requested for incentive compensation, $5,082,326 should be removed because it is related to financial measures that are unreasonable and unnecessary for the provision of T&D utility services. 94. Oncor reasonably calculated overtime expenses for the test year that are representative of its current and future work demands. 95. Oncor's one-time allocation of the pension and OPEB obligations, assets, and liabilities to comply with PURA § 36.065 were reasonable. 96. Oncor's FAS 87 pension costs for its qualified plan in the amount of $21,072,201 and for its nonqualified in the amount of $4,185,542 were reasonable and necessary. 97. Oncor's FAS 106 OPEB costs of $40,964,443 were reasonable and necessary. 98. Oncor's self-insurance plan with its threshold levels is in the public interest, is a lower cost alternative to purchasing commercial insurance, and provides its ratepayers the benefit of the savings. 99. In computing rates, liability insurance for self-insured utilities does not include liability coverage for intentional torts or for employee misconduct such as discrimination. 100. A liability and catastrophic property damage loss self-insurance program with an annual accrual of $ 33,284,430.45 and a target reserve of $66,568,860.90 is in the public interest. 101. The annual amortization figure calculated to cover Oncor's self-insurance reserve deficit over the next seven years is $20,417,612.29. 102. Oncor's affiliate entities, specifically EFH Corporate Service Company, EFH Properties Company, Luminant Generation Company LLC, Current Communications of Texas, L.P., TXY Energy Retail Company LLC, TXU Receivable Company, EFH Vermont Insurance Company, and EFH CG Holdings Company L.P., provided services to Oncor during the test year. 103. After adjustments agreed to during the hearing, Oncor requested affiliate-related O&M expenses of $21,734,501. 104. Oncor's affiliate-related expenses should be reduced by an additional $2,008,538, leaving remaining expenses of $19,725,963. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 13 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 105. Oncor's affiliate-related O&M expenses of $19,725,923 were reasonable and necessary and were not higher than charges to a third party or other affiliate for the same class of items. 106. During the test year, Oncor outsourced several business functions to Capgemini Energy LP (CGE) including information technology, customer care, revenue management, supply chain, finance and accounting, and human resources. 107. Oncor's contract with CGE used a combination of fixed and variable pricing, with the fixed pricing, called “Base Charge” being used for a predetermined scope and volume of services called the “In-Scope Baseline Services.” 108. For services provided beyond the in-scope baseline services, Oncor paid CGE additional fees in the form of additional resource charges (ARCs) and project charges. If Oncor used fewer in-scope services than the baseline, it received a credit in the form of reduced resource credits (RRCs). 109. Oncor requested recovery of $88,468,803 in the test year for CGE costs. 110. During the test year Oncor terminated its contract with CGE because Oncor was dissatisfied with that relationship and entered into a termination agreement. 111. DELETED. 111A. The total disputed ARC and project charges for the test year were $1,433,094.47. These charges should be disallowed making $87,035,705.53 the reasonable amount of outsourced expenses for 2007. 112. DELETED. 112A. It is reasonable for Oncor's cost of service to include $53,578,615 in energy-efficiency expenses for the test year. 113. Oncor's and its predecessors' depreciation rates have not been changed in 15 years. 114. The net salvage component for Oncor's transmission assets has remained unchanged for 15 years. 115. Except to the extent set forth in the findings of fact below, Oncor's depreciation analysis was the most thorough and reliable. 116. Oncor's proposed service lives are reasonable and should be used to set depreciation rates, except as set forth in the findings of fact below. 117. Oncor's land rights and easements associated with transmission lines and transmission substations (FERC Account 350) have an average service life of 100 years, not the 70 years proposed by Oncor. 118. The average service life for Oncor's distribution substations (FERC Account 362) is 50 years as recommended by Commission Staff, not the 48 years proposed by Oncor. 119. The average service life of Oncor's distribution poles, towers, and fixtures (FERC Account 364) is 41 years as proposed by ATOC, not the 38 years proposed by Oncor. 120. Net salvage value is the amount received for retired property (salvage) minus the cost to remove and sell the property. 121. Oncor's proposed net salvage values are reasonable and should be used to set depreciation rates, except as set forth below. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 14 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 122. The net salvage value of negative 33% for Oncor's T&D Structures and Equipment (FERC account 352/361) is the most reasonable of those proposed and should be adopted. 123. The net salvage value of a negative 34% for Oncor's Transmission Towers and Fixtures (FERC account 354) is the most reasonable and should be adopted. 124. DELETED. 124A. The net salvage value of negative 54% for Oncor's distribution overhead conductor (FERC account 365) is reasonable and should be adopted. 125. The net salvage value of negative 50% for Oncor's distribution underground conduit (FERC account 366) is reasonable and should be adopted. 126. The net salvage value of negative 5% for Oncor's distribution underground conductor (FERC account 367) is reasonable and should be adopted. 127. The prudent portion of Oncor's meter investment should be depreciated over an 11-year period. 128. DELETED. 128A. Oncor is not currently a member of an affiliated group eligible to file a consolidated federal income tax return. 128B. Oncor is a ring-fenced utility that has entered into a tax sharing agreement with EFH and its affiliates that requires Oncor to function as a stand-alone company. 128C. The Commission has neither addressed nor approved the tax-sharing agreement Oncor entered into with EFH and its affiliates. 128D. It is appropriate to treat Oncor as a stand-alone, conventional corporation for the purpose of determining its tax expenses. 128E. It is appropriate to determine Oncor's federal income tax expense included in its revenue requirement as if it were a stand-alone, conventional corporation. 128F. The Commission is not determining Oncor's federal income tax expense on the basis of its tax-sharing agreement with EFH. 129. DELETED. 130. DELETED. 131. Ad valorem property taxes as proposed by Oncor are reasonable and necessary expenses. 132. DELETED. 132A. Texas gross margin taxes in the amount of $17,338,957 are reasonable and necessary expenses. 133. DELETED. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 15 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 133A. Municipal franchise fees in the amount of 241,841,439 are reasonable and necessary expenses. 134. DELETED. 134A. Payroll taxes in the amount of $11,458,074 are reasonable and necessary expenses. 135. Under the Advanced Metering System (AMS) deployment plan approved in Oncor Electric Delivery Company LLC's Request for Approval of Advanced Metering System (AMS) Deployment Plan and Request for AMS Surcharge, Docket No. 35718 (August 29, 2008), Oncor is scheduled to replace virtually all its existing conventional and automated meters with advanced digital meters by the end of 2012. 136. The AMS surcharge proceeding was conducted in accordance with P.U.C SUBST. R. 25.130, which was adopted effective May 30, 2007. 137. Some form of automated metering has been available for twenty years or so. In 2004, however, Oncor began an initiative to replace its existing conventional meters with automated meters. 138. To implement its goal, Oncor chose three kinds of meters and associated infrastructures: powerline carrier (PLC), broadband over powerline (BPL), and radio frequency (RF). PLC meters have been deployed in some of Oncor's less densely populated service areas; BPL meters have been deployed in some more densely populated service areas. RF meters had not yet been deployed at the end of the test year. 139. Oncor has about 590,000 automated meters currently operating on its system. The Company also has many conventional meters still in place. 140. The Commission initiated its advanced metering rulemaking on July 26, 2005. The first workshop took place in September 2005 and a second in October 2005, with the Commission soliciting written comments to its questions on advanced metering on December 21, 2005. 141. DELETED. 141A. The AMS rule contains a waiver provision in § 25.130(g)(1)(C), which encompasses those PLC and BPL meters installed by Oncor that did not meet all of the functionality requirements. 142. In May 2007, after adoption of the final AMS rule, Oncor ceased purchasing PLC and BPL meters and canceled a pending order for BPL meters. 143. The advanced meters are significantly technologically superior to the automated BPL meters, and presumably to the PLC meters as well. 144. DELETED. 145. DELETED. 146. Oncor intended to avail itself of the AMS rule's surcharge provisions, as shown by its participation throughout the rulemaking process. 147. DELETED. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 16 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 148. A prudent manager would not necessarily have ceased the automated metering program after the September 2005 workshop. 149. DELETED. 150. DELETED. 151. DELETED. 152. DELETED. 153. DELETED. 153A. Oncor's automated meter investment should be allowed. 153B. Oncor had significant encouragement from the Commission to deploy both PLC and BPL meters. 154. Oncor's payment of $632,088 in cost paid to original-jurisdiction cities to reimburse them for their costs in appearing before the Commission and ERCOT in various regulatory matters are not reasonable and necessary operating expenses and cannot be recovered from ratepayers. Cost Allocation and Rate Design 155. DELETED. 155A. Oncor's proposed creation of a primary substation rate class consists of customers that provide their own distribution wires service. 156. DELETED. 156A. It is reasonable to establish the primary substation rate class for customers that take service directly out of a substation. 157. DELETED. 157A. Primary substation rate class service is designed to impose the cost that this rate class imposes on the system. 158. DELETED. 158A. Distribution customers should be permitted to avoid some distribution costs they do not impose on the system because these customers' hook up to the distribution system is at the substation. 159. DELETED. 159A. The ownership of private distribution lines distinguishes a primary substation rate class customer from a primary or secondary distribution customer. 160. DELETED. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 17 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 160A. A primary substation rate class customer does not own the initial transformation equipment located at the substation that transforms electricity from transmission voltage to a distribution voltage. 160B. Oncor's proposed addition of a primary substation rate class is reasonable and is approved. 161. For wholesale points of delivery (PODs) at a distribution substation, know as transformation service, Oncor offers Rate XFMR. For wholesale PODs on a distribution feeder line, known as distribution line service, Oncor offers Rate DLS. 162. In its cost-of-service study, Oncor allocated distribution costs to its wholesale customers based on system average costs, including the costs of its retail distribution system. 163. Oncor's cost-of-service study yielded increases of 88.66% for Rate XFMR and 147.37% for Rate DLS at Oncor's proposed rate increase level. 164. Oncor proposed to cap those increases at 50% for each class to mitigate rate shock, and to distribute the missing revenues among the other customer classes, except for its proposed primary substation class. 165. In Texas Utilities Electric Company Filing In Compliance With Subst. R. 23.67, Docket No. 15638 (Aug. 20, 1997), the Commission approved rates for Tex-La that was based on direct assignment. 166. In Docket No. 15638, the Commission concluded that direct assignment for the wholesale classes produced rates that were not unreasonably preferential, prejudicial, or discriminatory and that did not violate the principle of comparability. 167. In Docket No. 15638, the Commission stated that wholesale rates, however they are calculated, should not include costs that are strictly for providing retail service. 168. The facilities and costs for providing transformation service are the same, regardless of whether the customer is a wholesale or a retail customer. 169. Differences between wholesale and retail customers, including the wholesale customers' requirement to provide their own distribution facilities and the requirements for fair competition between the wholesale customers and Oncor, justify different treatment for those customers. 170. Although direct assignment would clearly be more difficult than the use of system-average costs, those difficulties are not particularly onerous or insurmountable. 171. Although Oncor's accounting system cannot identify the precise cost of individual items, such as individual poles, to perform a direct assignment study, Oncor can apply average costs to particular sections or components of its system. 172. In general, Oncor's backstanding capability, at least for Tex-La, does not consist of looped feeder lines, but of redundant transformers at substations providing the wholesale service. 173. DELETED. 173A. Direct assignment of costs may be considered for wholesale rate classes. 174. DELETED. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 18 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 174A. Oncor should be ordered to maintain data adequate for the direct assignment of costs to those wholesale classes and to prepare a direct assignment study for those classes for consideration in a future project to evaluate whether direct assignment should be used for allocating costs to the wholesale classes of customers or for consideration in Oncor's next rate proceeding. 175. The evidence in this case is inadequate to set rates based on direct assignment. 176. Rate XFMR and Rate DLS should be allocated the system-average rate increase in this case. 177. Oncor's calculation of its transmission rate based on the average of ERCOT coincident peak demand for the months of June, July, August, and September (4CP) is reasonable and should be approved. 178. Accounts 364 through 368 should be allocated based on class non-coincident peak (NCP) demand. 179. The costs of major account representatives should not be directly assigned. 180. Costs associated with economic development should be allocated using the customer allocation factor as proposed by Oncor. 181. Oncor's proposed allocation of rental revenues should be used in this proceeding. 182. Oncor should reallocate rental revenues according to their sources in the cost-of-service study in its next rate proceeding. 183. Oncor requested a weather normalization adjustment to adjust kilowatt-hour sales, class demands, and the associated revenue for those classes whose electricity usage was affected by abnormal weather conditions. 184. Oncor properly relied on its hourly weather information to determine the minimum and maximum temperatures of the day. 185. Oncor properly applied the adjustments to classes affected by the abnormal weather conditions. Oncor's weather normalization adjustments should be adopted without change. 186. Power factor is the ratio between the amount of energy supplied (kVA) and the actual amount of energy used (kW) to measure the amount of wasted energy. 187. Commercial/industrial customers that fail to improve their power factors to 95% within a reasonable period of time are charged for additional billing demands in accordance with Application Of TXU Electric Company For Approval Of Unbundled Cost Of Service Rate Pursuant To PURA § 39.201 and Public Utility Commission Substantive Rule § 25.344, Docket No. 22350 (Oct. 4, 2001). 188. Oncor has experienced a decrease in billing demands as a result of customers' actions to improve their power factor that should be reflected in the ratemaking through the proposed adjustment to avoid overstated revenues. 189. Demand ratchets have a substantial impact on the rates paid by customers with a maximum annual demand load of 20 kW or less (low loads) despite their having little ability to manage their energy consumption. 190. Oncor's proposal to waive the demand ratchet provisions for customers with maximum annual demand load of 20 kW or less is reasonable and should be adopted because low load customers, such as youth sports associations, non-profit organizations, churches, and small business owners, usually use electricity during off-peak hours and weekends and on a seasonal basis. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 19 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 191. Oncor's proposal to waive the demand ratchet provisions for all municipally-owned loads should not be adopted because it is unreasonably preferential and is not based on usage but is instead based solely on the identity of one group, municipalities. 192. The lighting class is unique in the combination of the public good it performs and its demand characteristics. 193. Oncor's proposal to limit a rate increase to the unmetered lighting service to 10% is reasonable and in the best interest of the public and should be approved. 194. Oncor's proposed franchise fee cost recovery factor rider (FFCRF) allows Oncor recovery of any incremental costs for increases to a specific municipality's franchise fee rate directly from the customers in that municipality every time a city raises its franchise fees. 195. Oncor's proposed Rider FFCRF should be rejected because it will create confusion with potentially over 100 different rates, is contrary to the Commission's policy to maintain uniform and simple rates, and discourages competition. 196. Oncor's proposed underground facilities cost recovery factor rider (UFCRF) allows Oncor to recover the increased costs associated with installing underground facilities directly from the city's customers. 197. Oncor's proposed Rider UFCRF should be rejected because it is inconsistent with the Commission's policy to maintain uniform, simple rates, and allows cities to allocate costs rather than the Commission. 198. Oncor proposed street light maintenance cost recovery factor rider (SLM) allows a city to pay for non-standard light maintenance services through a charge on customers within the city requesting this service. 199. Cities have the right to request non-standard light maintenance service through Oncor's discretionary charges. 200. Rider SLM creates non-uniform rates and allows Oncor to charge customers the cost of non-standard light maintenance performed in cities within its service territory, and therefore should be rejected. 201. Oncor requests approval of an energy-efficiency cost recovery factor rider (EECRF) to recover the costs of its 2009 energy- efficiency programs through a monthly customer charge on a per customer per class basis. 202. Rider EECRF is designed on the basis of cost causation because each class is allocated energy-efficiency costs for the benefits it receives, and these costs are uniformly imposed on the customers within that class. 203. Oncor's energy-efficiency program costs are recovered and adjusted annually and do not vary by energy usage or other variables. 204. Oncor's proposed Rider EECRF allows Oncor to recover all of its energy-efficiency program costs in a timely manner in conformance with the Commission rules that allow a utility to recover its energy-efficiency costs through a monthly customers charge, and should be approved. 205. Considering the Commission's January 30, 2009 order in this case regarding the motion for partial summary judgment, Oncor should not be required to continue offering Rider SCUD. 206. Oncor's nuclear decommissioning charge rider (NCF) should not be reallocated. 207. Oncor proposed to continue offering several existing retail discretionary services, with certain modifications and additions, which are billed to the party that incurs the cost. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 20 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 208. Oncor's proposed discretionary fees are reasonable and should be approved. 209. Several items in Oncor's specific terms and conditions and tariff language required certain changes to clarify the terms, specifically: a. Retail Tariff Section 6.1.2.2.4, should include the revised sentence: Company may, at its option and at its expense, relocate any Company-owned or non-Company-owned Meter. b. Retail Tariff Sections 6.1.2.2.7 should be modified to read: If Retail Customer desires Delivery System service that involves non-standard facilities as described in Section 6.1.2.2.1.2 of this Tariff, Retail Customer pays Company prior to Company's construction of non-standard facilities the total estimated cost of all non-standard facilities less the cost of standard facilities to meet Retail Customer's request. 210. No changes should be made to Section 4.5.7 of the Tariff for Transmission Service. 211. Commission Staff's recommended changes to Oncor's proposed Tariff for Retail Delivery Service and the Pro-forma Tariff for Retail Delivery Service should be approved. IV. CONCLUSIONS OF LAW 1. Oncor is an electric utility as defined by PURA § 31.002, and, therefore, it is subject to the Commission's jurisdiction under PURA §§ 14.001, 32.001, 33.001, 33.002, 33.051, 35.004, and 36.102. 2. Oncor is a T&D utility as defined in PURA § 31.002(19). 3. SOAH has jurisdiction over all matters relating to the conduct of the hearing in this case, including the preparation of a Proposal for Decision, pursuant to PURA § 14.053 and TEX. GOV'T CODE ANN. § 2003.049(b). 4. Oncor has the burden of proving that the rate change it is requesting is just and reasonable pursuant to PURA § 36.006. 5. Oncor provided adequate notice of this proceeding in compliance with P.U.C. PROC. R. 22.51. 6. Pursuant to PURA § 33.001, each municipality in Oncor'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. The Commission has jurisdiction over an appeal from a municipality's rate proceeding pursuant to PURA § 33.051. 8. The effective date of the change in rates approved in this case was extended to be consistent with P.U.C. SUBST. R. 25.241(i) and by agreement of Oncor, consistent with P.U.C. PROC. R. 22.33(c). 9. Oncor's overall revenues approved in this proceeding permit Oncor 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 in compliance with PURA § 36.052. 10. The rates approved in this proceeding are based on original cost, less depreciation, of property used and useful to Oncor in providing service, consistent with PURA § 36.053. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 21 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 11. 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). 12. PURA § 36.065(a) provides that electric utility rates shall include “expenses for pensions and other postemployment benefits, as determined by actuarial or other similar studies in accordance with generally accepted accounting principles, in an amount the regulatory authority finds reasonable.” 13. Oncor's requested ADFIT asset for its pension plan, OPEBs and FAS 112 ADFIT liabilities were properly included in its rate base is in accordance with PURA § 36.065. 14. Including the cash working capital (CWC) approved in this proceeding within Oncor's rate base is consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV) which allows a reasonable allowance for CWC be included in the rate base. 15. The return on equity and overall rate of return authorized in this proceeding are consistent with the requirements of PURA §§ 36.051 and 36.052. 16. The affiliate expenses approved in this proceeding and included in Oncor's rates are consistent with the requirements of PURA § 36.058. 17. PURA § 36.064 permits a utility to self-insure against “potential liability or catastrophic property loss, including windstorm, fire, and explosion losses, that could not have been reasonably anticipated and included under operating and maintenance expenses.” The Commission shall approve a self-insurance plan under that section if it finds the coverage is in the public interest, the plan, considering all of its costs, is a lower cost alternative to purchasing commercial insurance, and ratepayers receive the benefits of the savings. 18. Oncor's liability or catastrophic property loss self-insurance program as modified and approved is in accordance with PURA § 36.064 and P.U.C. SUBST. R. 25.231(b)(1)(G). 19. DELETED. 19A. PURA § 36.060 does not apply to Oncor as it is not currently a member of an affiliated group eligible to file a consolidated tax return. 19B. As a ring-fenced utility, Oncor's fair share of the tax savings is $0. 19C. Even though Oncor is a pass-through entity and not liable for federal income taxes, the Commission is required to include an amount for such taxes in its cost of service. Suburban Utility Corp. v. Public Utility Commission, 652 S.W.2d 358, 364 (Tex. 1983). 19D. Establishing Oncor's federal income tax expense as if it were a stand-alone, conventional corporation will result in rates that are just and reasonable. 20. Oncor's proposed energy-efficiency expenses and programs comply with PURA § 39.905. 21. DELETED. 21A. Oncor's purchase of automated meters after December 2005 met the prudence standard set out in Application of Gulf States Utilities for Authority to Change Rates, Docket No. 6525 (Oct. 15, 1986). © 2015 Thomson Reuters. No claim to original U.S. Government Works. 22 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 22. Direct assignment of costs to Oncor's wholesale classes is consistent with PURA § 36.003(b), other sections of PURA, and the Commission's Substantive Rules. 23. Oncor's rates, as approved in this proceeding, are just and reasonable in accordance with PURA § 36.003. V. ORDERING PARAGRAPHS 1. The Proposal for Decision prepared by the SOAH ALJs is adopted to the extent consistent with this Order. 2. Oncor's application is granted to the extent provided in this Order. 3. Oncor shall file tariffs consistent with this Order in Compliance Tariff Pursuant to Final Order in PUC Docket No. 35717 (Application of Oncor Electric Delivery Company, LLC for Authority to Change Rates), Docket No. 37677 within 20 days of the date of this Order. No later than 10 days after the date of the tariff filings, Commission Staff shall file its comments recommending approval, modification, or rejection of the individual sheets of the tariff proposal. Responses to the Commission Staff's 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 become effective upon 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, Oncor shall file proposed revisions of those sheets in accordance with the Commission's letter within 10 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. Oncor shall perform a direct assignment study for the wholesale classes and provide that study to the Commission in at future project to evaluate direct assignment of costs for wholesale classes or for consideration to assign wholesale costs according to that study in its next rate proceeding. 7. Oncor shall allocate revenues from rentals according to their sources in the cost-of-service study in its next rate proceeding. 8. 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 AT AUSTIN, TEXAS the 30th day of November 2009. I respectfully dissent on the consolidated tax savings adjustment issue, but otherwise join in the Commission's decisions on all other issues. I respectfully dissent on the automated meter recovery issue and the creation of a primary substation rate class issue, but otherwise join in the Commission's decisions on all other issues. Footnotes 1 Petition and Statement of Intent of Oncor Electric Delivery Company LLC (June 27, 2008), Oncor Initial Brief at 11 (March 4, 2009); Oncor Exhibits 1-6. 2 Description of Attendant Impacts and Number Running Schedules, Version 2, Scenario 1 (Aug. 10, 2009). © 2015 Thomson Reuters. No claim to original U.S. Government Works. 23 Application of Oncor Electric Delivery Company, LLC for..., 2009 WL 4724725... 3 Tr. Vol. 17 at 3292-3293 (Feb. 9, 2009). 4 Suburban Util. Corp. v. Pub. Util. Comm'n, 652 S.W.2d 358 (Tex. 1983). 5 See 26 U.S.C. § 1361. 6 652 S.W.2d at 364. 7 Oncor's Exceptions to the Proposal for Decision at 32 (June 16, 2009). 8 Id. at 31. 9 PFD at 43. 10 Oncor's Exception to the Proposal for Decision at 86. 11 Dane A. Watson Direct Testimony, Oncor Ex. 15, Attachment DAW-2 at 65. 12 Nara Srinivasa Revised Direct Testimony, Staff Ex. 8A at 58. 13 Suburban Util. Corp. v. Pub. Util. Comm'n, 652 S.W.2d 358 (Tex. 1983). 14 See 26 U.S.C. § 1361. 15 652 S.W.2d at 364. 16 See Pub. Util. Comm'n v. GTE-Southwest, Inc., 901 S.W.2d 401, 408-12 (Tex. 1995). 17 Oncor's Response to Order Requesting Briefing at 3-4 (Oct. 29, 2009). 18 See, e.g., Commission Staff's Response to Order Requesting Briefing at 2 (Oct. 29, 2009). 19 901 S.W.2d at 411, “tax expenses will always be a hypothetical amount.” 20 Id. 21 Id. 22 PURA § 36.062(4); 901 S.W.2d at 411. 23 PURA § 36.003(a). 24 Id. § 36.003(b), (c). 25 Id. § 36.051. 26 PFD at 184. 27 See Oncor's Response to Order Requesting Briefing at 12-13; see also Moyston v. New Mexico Pub. Serv. Comm'n, 412 P.2d 840, 849-50, 63 P.U.R.3d 522, ___ (N.M Ctt. App. 1966) (discussing a similar tax treatment in Re Southern Union Gas Company, 36 P.U.R.3d 60 (1960), on remeand, 40 P.U.R.3d (N.M. Pub. Serv. Comm'n 1961)). 28 PURA § 36.060(a) (emphasis added). 29 Mary Jacobs Direct Testimony, Commission Staff Ex. 5 at 26-27. 30 Id. 31 Id. 32 Tr. Vol. 7 at 1241-1242 (Jan. 23, 2009). 33 Oncor's Initial Post Hearing Brief at 192-3 (Mar. 27, 2009). 34 Id. at 199-200. 35 PFD at 214. 36 PFD at 223, 224. End of Document © 2015 Thomson Reuters. No claim to original U.S. Government Works. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 24 APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342... 2010 WL 5240342 (Tex.P.U.C.) Slip Copy APPLICATION OF ENTERGY TEXAS, INC. FOR AUTHORITY TO CHANGE RATES AND RECONCILE FUEL COSTS PUC Docket No. 37744 SOAH Docket No. XXX-XX-XXXX Texas Public Utility Commission December 13, 2010 ORDER Before Smitherman, Chairman, Nelson, and Anderson Jr., Commissioners. BY THE COMMISSION: This Order addresses the application of Entergy Texas, Inc. (ETI) for authority to change rates and reconcile fuel costs. ETI, Commission Staff, the Office of Public Utility Counsel (OPUC), the Steering Committee of Cities Served by ETI (Cities), 1 Texas Industrial Energy Consumers (TIEC), The Kroger Company (Kroger), and Wal-Mart Stores Texas, LLC and Sam's East, Inc. (collectively Wal-Mart), through their duly authorized representatives entered into and filed a stipulation and settlement agreement that resolves all of the issues in this proceeding except the issues related to ETI's proposal for competitive generation service. Cottonwood Energy, L.P. and the State of Texas agencies and institutions of higher education (State Agencies) did not join but do not oppose the stipulation. The Commission severed the competitive generation service issues into Docket No. 38951 2 in Order No. 14. The Commission adopts the following findings of fact and conclusions of law: I. Findings of Fact Procedural History 1. On December 30, 2009, ETI filed an application requesting approval of (1) base rate tariffs and riders designed to collect an overall revenue requirement of $1,758.4 million, which includes a total non-fuel retail revenue requirement of $838.3 million (base rate revenues of $486 million plus revenue from riders of $352.3 million); (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying ETI's application; (3) a request for final reconciliation of ETI's fuel and purchased power costs for the reconciliation period from April 1, 2007 to June 30, 2009; and (4) certain waivers to the instructions in RFP Schedule V accompanying ETI's application. 2. The 12-month test year employed in ETI's filing ended on June 30, 2009. 3. 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. ETI also published one-time supplemental notice by publication in newspapers and by bill insert. 4. The following parties were granted intervenor status in this docket: OPUC, Cities, Cottonwood, Kroger, State Agencies, TIEC, and Wal-Mart. Commission Staff was also a participant in this docket. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 1 APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342... 5. On January 4, 2010, the Commission referred this case to the State Office of Administrative Hearings (SOAH) for processing. 6. On February 19, 2010, the ALJs issued Order No. 3, which approved an agreement between ETI, Staff, Cities, State Agencies, OPUC, TIEC, Kroger, and Wal-Mart, to (1) establish an interim rate increase of $17.5 million annually above ETI's then- existing base rates commencing with service rendered on and after May 1, 2010 subject to true-up and refund for service rendered prior to September 13, 2010 to the extent final overall rates established by the Commission amounted to less than a $17.5 million rate increase; (2) extend the jurisdictional deadline by which the Commission must issue a final order on the Company's rate request from July 5, 2010 to November 1, 2010; (3) establish a September 13, 2010 effective date for rates such that, notwithstanding the extension of the jurisdictional deadline, the final overall rates established by the Commission would relate back to service rendered on and after September 13, 2010; (4) require ETI to publish supplemental notice, once in newspapers and by a bill insert, setting forth the effect of its proposed rate change in terms of the percentage increase in non- fuel revenues; and (5) establish a procedural schedule and discovery deadlines for this proceeding. Order No. 3 also granted Mr. Kurt Boehm's motion for admission pro hac vice as counsel for Kroger and ETI's February 3 and February 11, 2010 petitions for review of cities' ordinances and motions to consolidate with respect to the rate decisions adopted by the Cities of Ames, Anderson, Bedias, Bevil Oaks, Bremond, Caldwell, Calvert, Chester, China, Colmesneil, Corrigan, Cut and Shoot, Daisetta, Dayton, Devers, Franklin, Groveton, Hardin, Hearne, Iola, Kosse, Kountze, Liberty, Lumberton, Madisonville, Midway, New Waverly, Normangee, Nome, Patton Village, Plum Grove, Riverside, Rose Hill Acres, Somerville, Taylor Landing, Todd Mission, Trinity, and Woodville. 7. On June 14, 2010, the ALJs issued Order No. 6 granting Staffs June 1, 2010 motion and severing rate case expense issues to Docket No. 38346. 3 Through Order No. 6, the ALJs also granted ETI's March 12, April 29, and May 17 petitions for review and motions to consolidate with respect to the rate decisions adopted by the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Panorama Village, Pine Forest, Pinehurst, Port Arthur, Port Neches, Roman Forest, Rose City, Shenandoah, Shepard, Silsbee, Sour Lake, Splendora, Vidor, West Orange, Willis, Woodbranch Village, and Woodloch. 8. The hearing on the merits commenced on July 13, 2010 and was immediately recessed in order to facilitate settlement negotiations. The hearing was again convened on July 15, 2010, at which time the signatories announced their intent to continue settlement discussions to resolve all issues related to the Company's application with the exception of those related to ETI's proposal for competitive generation service (CGS) and associated riders. 9. On August 6, 2010, the signatories submitted the stipulation resolving all outstanding issues regarding the Company's application with the exception of those related to ETI's CGS proposal. Under the stipulation, ETI will be allowed to implement base rate tariffs and riders designed to collect an overall revenue requirement of $1,614.9 million, 4 which includes a total non- fuel retail revenue requirement of $694.9 million (base rate revenues of $599 million plus revenue from riders of $95.9 million). The signatories also submitted, on August 6, 2010, an agreed motion to revise interim rates and to consolidate the severed rate-case expense docket. The interim rates requested in the agreed motion mirrored the final rates proposed for Commission approval in the stipulation. The agreed motion further requested that the ALJs consolidate with the instant proceeding Docket No. 38346, related to severed Docket No. 37744 rate case expense issues, and admit the parties' pre-filed exhibits into evidence. 10. On July 16 and July 20, 2010, the ALJs held the hearing on the merits with respect to ETI's CGS proposal. 11. On August 9, 2010, the ALJs issued Order No. 12, granting approval of revised interim rates for usage on and after August 15, 2010. 12. On October 5, 2010, the ALJs issued a proposal for decision regarding issues related to ETI's CGS proposal. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 2 APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342... 13. On October 5, 2010, the ALJs issued Order No. 13, ordering the consolidation of Docket No. 38346, related to severed rate- case expense issues, into the instant proceeding, admitting evidence, and returning this docket to the Commission consistent with the agreed motion filed on August 6, 2010. 14. The Commission considered this Docket at the November 10, 2010 and December 1,2010 open meetings. 15. On November 30, 2010 ETI filed an unopposed motion to sever the competitive CGS issues from the settled issues in this docket. The Commission granted the motion at the December 1, 2010 open meeting and the Commission's decision was memorialized in Order No. 14 issued on December 3, 2010. The CGS issues were severed into Docket No. 38951 in Order No. 14. Description of the stipulation and Settlement Agreement 16. The signatories to the settlement stipulated that ETI should be allowed to implement an initial overall increase in base- rate revenues of $59 million for usage on and after August 15, 2010. The signatories further stipulated that they would request approval of interim rates by the ALJs presiding or by the Commission, as necessary, to ensure timely implementation of this initial rate increase. The signatories further stipulated that ETI 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, the first billing cycle for the revenue month of May. 17. The signatories agreed that ETI's authorized return on equity shall be 10.125% and its weighted average cost of capital shall be 8.5209%. 18. The signatories stipulated that the amount of rate increase authorized under finding of fact 16 includes rate-case expenses and contemplates their full amortization in 2010, and that this amount constitutes the full and final recovery of all rate-case expenses relating to Docket No. 37744. 19. The signatories stipulated to the amount of transmission and distribution invested capital by function as of June 30, 2009 as set out in attachment 1 to the stipulation. 20. The signatories stipulated that the Company's proposed purchased-power recovery rider will not be approved in this docket, and purchased capacity costs will be included in base rates. 21. The signatories stipulated that the Company's proposed transmission cost recovery factor (TCRF) will not be approved in this docket. The signatories stipulated to the baseline values as shown in attachment 2 to the stipulation to be used in the Company's request, if any, for a TCRF in a separate proceeding. 22. The signatories agreed that ETI's proposed cost-of-service adjustment rider and formula rate plan will not be approved in this docket. 23. The signatories stipulated that the Company's proposed renewable-energy-credit rider will not be approved in this docket, and the Company's renewable-energy-credit costs shall be recovered in base rates. The signatories further stipulated that a transmission customer that opts out pursuant to P.U.C. SUBST. R. 25.1730(j) shall receive a credit that offsets the amount of renewable-energy-credit costs that are recovered in base rates from the transmission customer. 24. The signatories agreed that ETI's proposed remote-communications-link rider should be approved as filed by the Company. 25. The signatories agreed that ETI's proposed market-valued-energy-reduction service rider will not be approved in this docket. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 3 APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342... 26. The signatories reached the following specific agreements regarding rate design as a part of the overall resolution of this docket: a. Rate Schedule IS. Rate Schedule IS will be opened to new business In the Company's next base-rate case, the amount of interruptible credits recoverable from Texas retail customers shall be limited to an increase of $1 million more than the amount requested in this docket (or a total of $6.8 million); provided, however, that in the next rate case, the Company may request an exception to this limitation upon a showing that the test-year credit amount in excess of the $6.8 million cap is both cost effective and necessary to meet the Company's generation reserve margin requirement. The signatories further agreed that the Company will not offer additional interruptible service if the availability of total interruptible service supplied by the Company under all interruptible service riders exceeds 5% of the projected aggregate Company peak demand unless the additional level of interruptible service offered in excess of the 5% cap is both cost effective and necessary to meet the Company's generation reserve margin requirement. To the extent that the credit amount or participation level exceeds the limitations described in this paragraph and the Company includes test-year credits over the $6.8 million credit-amount cap or additional participation in excess of the 5% participation-level cap in its next rate case, the Company shall have the burden to prove whether those test- year credits or participation levels meet the standards established in this paragraph for inclusion in the test year. The standards in this paragraph are in addition to any requirements in PURA for inclusion of costs in rates. The signatories further agreed to the Schedule IS revisions shown on attachment 3 to the stipulation. b. Rate Schedule IHE. The signatories agreed that no change shall be made to rate schedule IHE in this docket. c. Lighting Class Rates. The signatories stipulated that the language under the paragraph relating to rate group C in rate schedule SHL will be revised to reflect that, where the Company agrees to install facilities other than its standard street light fixture and lamp as provided under Rate Group A, a lump sum payment will be required, based upon the installed cost of all facilities excluding the cost of the standard street light fixture and lamp, and the customer will be billed under rate group A. e. Electric Extension Policy. The signatories agreed to the line-extension terms and conditions as reflected in attachment 4 to the stipulation. f. Life-of-Contract Demand Ratchet. The signatories agreed that the life-of-contract demand ratchet provision in rate schedules Large Industrial Power Service, Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day, Large General Service, and Large General Service-Time of Day shall be excluded from rate schedules in ETFs next rate case. The signatories further stipulated 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 shall not exceed the level in effect on August 15, 2010 for existing customers. g. Residential Customer Charge. The signatories agreed that the residential customer charge shall be increased to $5.00. h. Non-Sufficient Funds Charge. The signatories agreed that the non-sufficient funds charge shall be increased to $15.00. 27. The signatories agreed to the class cost allocation set forth in attachment 5 to the stipulation. 28. The signatories stipulated that the appropriate allocation between ETI's wholesale and retail jurisdictions of baseline values and costs to be included in a TCRF is to be addressed in the proceeding, if any, in which ETI seeks approval of a TCRF. 29. The signatories stipulated that no party waives its right to address in any subsequent proceeding the appropriate treatment for Texas retail ratemaking purposes of power sales between ETI and Entergy Gulf States Louisiana, L.L.C. 30. The signatories reached the following specific agreements regarding fuel-related issues as part of the overall resolution of this docket: © 2015 Thomson Reuters. No claim to original U.S. Government Works. 4 APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342... a. Agreed Fuel Disallowance. The Company stipulated to a fuel disallowance of $3.25 million not associated with any particular issue raised by the signatories. The disallowance will be allocated pro rata with interest over each month of the reconciliation period and reflected in the refund in Docket No. 38403. 5 The signatories stipulated that the Company's fuel costs shall be finally reconciled for the reconciliation period of April 1, 2007 through June 30, 2009. b. Rider IPCR. The signatories agreed that ETI's eligible Rider IPCR costs for the period April 1, 2007 through the date the rider terminated shall be finally reconciled with a disallowance of $300,000. The signatories further agreed that the under-recovered balance of Rider IPCR costs shall be booked as fuel expense in the month in which the Commission issues an order adopting the stipulation; provided, however, that the under-recovered balance shall be allocated to customer classes using A&E4CP. c. Rough Production Cost Equalization (RPCE) Payments. The signatories agreed that ETI will credit an additional $18.6 million to Texas fuel-factor customers, which the signatories stipulated represents the remaining portion of RPCE payments ETI received in 2007 that were at issue in Docket No. 35269. 6 The RPCE credit shall be allocated to rate classes based on loss-adjusted kilowatt hours at plant for calendar year 2006. For customers in the Large Industrial Power Service rate class, the credit will be refunded based on the customer's actual kWh usage during the billing months of January 2006 through December 2006. Upon issuance of a final order approving the stipulation, the RPCEs shall be credited to customers as a separate one- month bill credit in the same form as the RPCEA Rider last approved in Docket No. 38098. 7 ETI agreed that it will terminate all appeals related to Docket No. 35269. 31. The signatories agreed that ETI will continue its accrual of storm-cost reserves at the level of $3.65 million annually and that this amount shall be subsumed in the base-rate revenue increase described in finding of fact 16 above. 32. The signatories agreed that ETI shall maintain River Bend depreciation rates at current levels, i.e., based on a 60-year life. River Bend decommissioning costs will be set at $2,019,000 annually, which is based upon a labor-factor escalation rate of 1.67%, an energy-factor escalation rate of 0.25%, and a waste-burial-factor-escalation rate of 1.71%, resulting in an overall escalation rate of 3.62%, and net investment yields as follows: Nuclear-Decommissioning-Trust Projected Returns Tax-Qualified Investment Non-Tax-Qualified Investments 2010 5.475% 5.057% 2011 5.837% 5.236% 2012 6.306% 5.567% 2013 6.304% 5.607% 2014 6.481% 5.896% 2015 6.493% 5.909% 2016 6.412% 5.826% 2017 6.412% 5.830% 2018 6.364% 5.790% © 2015 Thomson Reuters. No claim to original U.S. Government Works. 5 APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342... 2019 6.316% 5.748% 2020 6.268% 5.712% 2021 6.220% 5.670% 2022 2.503% 5.458% 2023 5.817% 5.055% 2024 5.382% 4.628% 2025 5.036% 4.516% 2026-2034 4.920% 4.409% 33. The signatories stipulated that the Company's depreciation rates for non-River Bend production plant, transmission, distribution, and general plant will remain at current levels and the Company will maintain its accounting records on a prospective basis for purposes of depreciation accrual, depreciation reserve, retirements, additions, salvage, and cost of removal by FERC account. Consistency of the Agreement with PURA and the Commission Requirements 34. Considered in light of (1) the pre-filed testimony by the parties entered into evidence and (2) the additional evidence and testimony admitted during the course of the hearing on the merits on the Company's application, the stipulation is the result of compromise from each signatory, and these efforts, as well as the overall result of the stipulation viewed in light of the record evidence as a whole, support the reasonableness and benefits of the terms of the stipulation. 35. The evidence addressed in finding of fact 34 demonstrates that the rates, terms, and conditions resulting from the stipulation are just and reasonable and consistent with the public interest. 36. The total level of the Texas retail revenue requirement contemplated by the stipulation will allow ETI the opportunity to earn a reasonable return over and above its reasonable and necessary operating expense. 37. The stipulated revenue requirement is consistent with applicable provisions of PURA chapter 36 and the Commission's rules. 38. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, they are reasonable and necessary for each class of affiliate costs presented in ETI's application. 39. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, the price charged to ETI is not higher than the prices charged by the supplying affiliate for the same item or class of items to its other affiliates or divisions, or a non-affiliated person within the same market area or having the same market conditions. 40. The retail revenue requirement in the stipulation does not include any expenses prohibited from recovery under PURA. 41. A return on equity of 10.125% and a weighted average cost of capital of 8.5209% for ETI should be adopted consistent with the stipulation. 42. The agreed rate-design provisions and terms and conditions of service included in the stipulation are just and reasonable. 43. The treatment of rate-case expenses described in the stipulation is reasonable. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 6 APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342... 44. The Company's proposed remote-communications-link rider as filed by the Company is reasonable. 45. The depreciation rates agreed to in the stipulation are just and reasonable. 46. The recovery of $2,019,000 annually for decommissioning costs of nuclear production assets based on the factors agreed to in the stipulation is reasonable. 47. A $3.65 million annual storm cost accrual is reasonable. 48. The class allocation methodologies described in the stipulation are just and reasonable. 49. The fuel and IPCR-related provisions of the stipulation are reasonable. II. 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, 36.001-.111, 36.203, 39.452, and 39.455. 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, the Texas Administrative Procedure Act, 8 and Commission rules. 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)(1)-(3). 6. This docket contains no remaining contested issues of fact or law. 7. The stipulation, taken as a whole, is a just and reasonable resolution of all issues it addresses; results in just and reasonable rates, terms, and conditions; is supported by a preponderance of the credible evidence in the record; is consistent with the relevant provisions of PURA; and is consistent with the public interest. 8. ETI has properly accounted for the amount of fuel and IPCR-related revenues collected pursuant to the fuel factor and Rider IPCR. 9. The revenue requirement, cost allocation, revenue distribution, and rate design implementing the stipulation result in rates that are just and reasonable, comply with the ratemaking provisions in PURA, and are not unreasonably discriminatory, preferential, or prejudicial. 10. Based on the evidence in this docket, the overall total invested capital through the end of the test year meets the requirement in 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. 11. ETI has met its burden of proof in demonstrating that it is entitled to the level of retail base rate and rider revenue set out in the stipulation. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 7 APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342... 12. ETI has met its burden of proof in demonstrating that the rates resulting from the stipulation are just and reasonable, and consistent with PURA. III. Ordering Paragraphs 1. ETI's application seeking authority to change its rates; reconcile its fuel and purchased power costs for the Reconciliation Period from April 1, 2007 to June 30, 2009; and for other related relief is approved consistent with the above findings of fact and conclusions of law. 2. Rates, terms, and conditions consistent with the stipulation are approved. 3. The tariffs and riders consistent with the stipulation are approved for the initial and second step rate increases. 4. ETI's request for waivers of RFP instructions (RFP Schedule V) is granted. 5. ETI shall adjust decommissioning expense related to the River Bend Nuclear Generating Station consistent with the terms of this Order. 6. Neither the stipulation and settlement agreement nor this Order constitutes the Commission's agreement with, or consent to, the manner in which ETI, or any entity affiliated with ETI, has interacted with any decommissioning trust to which ETI or its ratepayers have made contributions or provided funds. Furthermore, this Order in no way constitutes a waiver or release of any conduct, whether or not such conduct occurred before the date of this Order, that may constitute a violation of any provision of state law, including, without limitation, the rules and regulations of this Commission relating to nuclear decommissioning trust funds; or prevents the Staff of the Commission from opening an investigation and taking enforcement action relating to violations of such rules and regulations. 7. Nothing contained in this Order constitutes the consent or approval, explicit or implied, of any modification, amendment or clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River Bend Station. Without limiting the foregoing, nothing contained in this Order shall constitute the consent or approval of any modification, amendment, or clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River Bend Station, which is made to address any concerns raised by the NRC in its Request for Additional Information regarding the River Bend Station dated March 11, 2010. 8. The Rider IPCR costs and eligible fuel costs requested by ETI are, consistent with this Order, reconciled through June 30, 2009, and are approved consistent with the stipulation. 9. ETI shall adjust its fuel over/under recovery balance consistent with the findings in this Order. 10. ETI shall file an RPCEA Rider consistent with the above findings of fact and conclusions of law to be effective with the first billing cycle of the billing month immediately following the effective date of this Order.. 11. Because the final approved rates are equal to or higher than the interim rates adopted in Order No. 3, no refund of the interim rates authorized by Order No. 3 is necessary. 12. The interim rates approved in Order No. 12 are herby approved for the initial step rate increase contemplated by the stipulation, and ETI shall implement the second step rates for bills rendered on and after May 2, 2011, the first billing cycle for the revenue month of May. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 8 APPLICATION OF ENTERGY TEXAS, INC. FOR..., 2010 WL 5240342... 13. Within 30 days of the date of this Order, ETI shall file a clean copy of all of the tariffs and schedules approved in this docket and a clean copy of the attachments to the stipulation. 14. The entry of this Order consistent with the stipulation does not indicate the Commission's endorsement of any principle or method that may underlie the stipulation. Neither should entry of this Order be regarded as a precedent as to the appropriateness of any principle or methodology underlying the stipulation. 15. 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. SIGNED AT AUSTIN, TEXAS the 13 th day of December 2010 Footnotes 1 Steering Committee of Cities is comprised of the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange. 2 Application of Entergy Texas, Inc. for Approval of Competitive Generation Service Tariff (Issues Severed From Docket No. 37744), Docket No. 38951. 3 Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No 37744, Docket No. 38346. 4 This figure includes fuel at test year prices. If current fuel prices are substituted for test year fuel prices, the overall revenue requirement figure would be $ 1,504.0 million. 5 Application of Entergy Texas, Inc. to Implement an Interim Fuel Refund, Docket No. 38403, Order (Sept. 16,2010). 6 Compliance Filing of Entergy Texas, Inc. Regarding Jurisdictional Allocation of 2007 System Agreement Payments, Docket No. 35269, Order (Jan. 7, 2009). 7 Application of Entergy Texas, Inc. for Authority to Implement New RPCEA Rate, Docket No. 38098, Order (July 1,2010). 8 TEX. GOV'T CODE ANN. Chapter 2001 (Vemon 2007 and Supp. 2009). End of Document © 2015 Thomson Reuters. No claim to original U.S. Government Works. © 2015 Thomson Reuters. No claim to original U.S. Government Works. 9 PUC DOCKET NO. 38339 SOAH DOCKET NO. XXX-XX-XXXX APPLICATION OF CENTERPOINT § PUBLIC UTILITY COMMISSION ELECTRIC DELIVERY COMPANY, § LLC, FOR AUTHORITY TO CHANGE § OF TEXAS RATES § ORDER ON REHEARING 1 This Order addresses the application of CenterPoint Electric Delivery Compan~~ LLC,for .,.Q authority to change its rates. On June 30, 2010, CenterPoint filed its application with the Public Utility Commission of Texas requesting authority to increase its transmission and distribution rates and to reconcile costs related to its advanced metering system (AMS) deployment. CenterPoint originally requested a total net increase of $110 million: $18 million represented the net increase associated with transmission service and $92 million associated with retail delivery service. CenterPoint requested a rate of return on investment of 9.0%, based on a proposed capital structure having 50-50 ratio of debt to equity; a 6.74% cost of debt; and a return on equity of 11.25%. On December 3, 2010, the State Office of Administrative Hearings (SOAH) administrative law judges (AUs) issued a proposal for decision in which they recommended an overall rate increase for CenterPoint of $21.483 million. 1 For the reasons discussed in this Order, the Commission adopts in part and rejects in part the proposal for decision, including findings of fact and conclusions of law, and determines that CenterPoint's appropriate system- wide adjusted rates will lead to a retail revenue increase of $14.65 million and an overall revenue requirement increase of $2.4 million for both retail and wholesale combined.2 1 Proposal for Decision (PFD), Attachment ALJ-3 at I, line 10, column 2 "Difference between ALJs' Rec. and CNP, current revenues." (Dec. 3, 2010). 2 Revised Number Runs and Associated Workpapers, Attachment Comm-3 AFTER Postage Stamp Update, at I, line LO, column 2 (Feb. 18, 2011). 000000001 PUC Docket No. 38339 Order on Rehearing Page 22 of47 SOAH Docket No. XXX-XX-XXXX 75A. CenterPoint's overall rate of return is as follows: CAPITAL WEIGHTED AVG COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL LONG-TERM DEBT 55.00% 6.74% 3.71% COMMON EQUITY 45.00% 10.00% 4.50% TOTAL 100.00% 8.21% Cost of Service 76. CenterPoint's test-year total transmission operations and maintenance (O&M) expense in FERC accounts 560 through 573 as adjusted by the Commission in the amount of $234.721 million is reasonable and necessary. 77. CenterPoint's test-year total-distribution O&M expense in FERC accounts 580 through 598 as adjusted by the Commission in the amount of $188.132 million is reasonable and necessary. 78. CenterPoint' s proposed $7 .15 million O&M expenditure related to storm hardening is reasonable and necessary. 79. CenterPoint's requested total-customer-services-and-information expense of $35.54 million is reasonable and necessary. 80. CenterPoint's Commission-adjusted administrative-and-general-expense request of $178.178 million is reasonable and necessary. 81. The evidence demonstrates that CenterPoint's short-term incentive compensation plan (STI) is a reasonable and necessary component of a total compensation package required to recruit, retain, and motivate employees. 82. CenterPoint's long-term incentive-compensation plan (LTI) is not a reasonable and necessary component of CenterPoint' s total compensation package. 83. The corporate and financial goals of STI are directly tied to metrics such as customer service and safety. 000000022 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 ETI 2011 Rate Case ETI EXHIBIT NO. 1 DOCKET NO. 39896 APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION TEXAS, INC. FOR AUTHORITY § TO CHANGE RATES AND § OF TEXAS RECONCILE FUEL COSTS § ENTERGY TEXAS, INC.’S STATEMENT OF INTENT AND APPLICATION FOR AUTHORITY TO CHANGE RATES AND RECONCILE FUEL COSTS TO THE HONORABLE PUBLIC UTLITY COMMISSION OF TEXAS: Pursuant to Sections 14.001, 32.001, 32.101, 36.101 through 36.111 and 36.203 through 36.206 of the Public Utility Regulatory Act (“PURA”)1 and pursuant to applicable Public Utility Commission of Texas (“Commission” or “PUCT”) Substantive and Procedural Rules, Entergy Texas, Inc. (“ETI” or “the Company”) respectfully requests that the Commission approve: (1) base rate tariffs and riders designed to collect a total non-fuel retail revenue requirement for ETI of approximately $841.9 million; (2) the complete set of proposed tariff schedules presented in Schedule Q-8.8 of the Electric Utility Rate Filing Package for Generating Utilities (“Rate Filing Package” or “RFP”) that accompanies this Application; (3) the Company’s request for reconciliation of its fuel and purchased power costs and fuel factor revenues for the Reconciliation Period from July 1, 2009 to June 30, 2011, pursuant to P.U.C. SUBST. R. 25.236; and (4) the waivers to the Rate Filing Package instructions presented in RFP Schedule V that accompany this Application. 1 TEX. UTIL. CODE ANN. Title 2. 1 2011 ETI Rate Case 1-1 In support of these requests, ETI states: I. Parties and Jurisdiction 1. ETI is an electric utility, a public utility, and a utility as those terms are defined in PURA §§ 11.004(1) and 31.002(6). 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. ETI’s business address is 350 Pine Street, Beaumont, Texas 77701. Its mailing address is P.O. Box 2951, Beaumont, Texas 77704-2951. Its telephone number is (409) 838-6631. ETI’s regulatory affairs office in Austin, Texas is located at 919 Congress Avenue, Suite 840, Austin, Texas 78701, telephone number (512) 487-3999, and facsimile number (512) 487-3998. 4. ETI is a wholly-owned subsidiary of Entergy Corporation, which is a “holding company” pursuant to FERC regulations under the Public Utility Holding Company Act of 2005.2 Entergy Corporation is the parent company of six other rate-regulated utilities in the United States in addition to ETI;3 two regulated non- profit service companies that were established under the authority of the Securities and Exchange Commission but are now under the oversight of FERC;4 and various other domestic and foreign companies. Entergy Corporation’s domestic rate-regulated utility operating companies (“Entergy Operating Companies” or “Operating Companies”) operate an interconnected transmission and generation system governed by the Entergy System Agreement and 2 18 C.F.R. Part 366. 3 Entergy Arkansas, Inc.; Entergy Gulf States Louisiana, L.L.C.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.; Entergy New Orleans, Inc.; and System Energy Resources, Inc. (“SERI”). SERI owns the Grand Gulf nuclear plant and sells its output exclusively to Entergy Operating Companies other than ETI. 4 Entergy Services, Inc. and Entergy Operations, Inc. 2 2011 ETI Rate Case 1-2 associated Service Schedules MSS-1 through MSS-7,5 which are under FERC’s exclusive jurisdiction. 5. The Commission has exclusive original jurisdiction over this Application for service provided to environs customers and to customers within the corporate limits of those cities within ETI’s service territory that have ceded their regulatory jurisdiction to the Commission, as well as over the reconciliation of fuel and purchased power costs, pursuant to PURA §§ 14.001, 32.001, 32.002, 36.101 through 36.111 and 36.203 through 36.206. 6. The Company’s proposed effective date for the rate change is 35 days after the date of the filing of this Application. II. Authorized Representative, Counsel, and Designation of Service Location 7. ETI’s authorized representative is Mr. Jack Blakley, Vice President, Regulatory Affairs–Texas, who may be contacted at ETI’s regulatory affairs office in Austin, Texas (address, telephone, and facsimile numbers listed in ¶ 3). 8. ETI’s co-lead counsels are: Steven H. Neinast John F. Williams Paula Cyr Jay Breedveld Assistants General Counsel Duggins Wren Mann & Romero, Entergy Services, Inc. LLP 919 Congress Avenue, One American Center Suite 701 600 Congress, Suite 1900 Austin, Texas 78701 P.O. Box 1149 (512) 487-3957 telephone Austin, Texas 78767-1149 (512) 487-3958 facsimile (512) 744-9300 telephone (512) 744-9399 facsimile 5 MSS-1 is the tariff for equalizing the Operating Companies’ generating capability and ownership cost incidental to such capability. MSS-2 is the tariff for equalizing the Operating Companies’ investment in bulk transmission plant. MSS-3 is the tariff governing the exchange of electric energy and the allocation of rough production cost equalization payments among the Operating Companies. MSS-4 is the tariff governing unit power purchases between Operating Companies. MSS-5 is the tariff that distributes profits from sales of energy and power to unaffiliated companies for the joint account of all Operating Companies. MSS-6 is the tariff that provides a means to distribute the cost of the system operations center (the system dispatch center). MSS-7 is a tariff providing a procedure for protecting those Operating Companies that elect to participate therein from incurring higher fuel and purchased power costs as a result of the merger between Entergy Corporation and Gulf States Utilities Company. 3 2011 ETI Rate Case 1-3 9. ETI requests that the Commission, the presiding officers, the State Office of Administrative Hearings, the Commission Staff, and the parties serve all papers (orders, discovery, motions, etc.) regarding this Application on Mr. Neinast’s office, as listed in the previous paragraph. III. Proposed Tariffs 10. ETI’s proposed revisions to its tariffs are provided in RFP Schedule Q-8.8. ETI’s complete Rate Filing Package is filed contemporaneous with this Application. IV. Summary of Filing 11. The prefiled direct testimony of ETI witness Joseph F. Domino explains the structure of this filing and introduces each of the witnesses. ETI’s filing addresses: (1) base rates and riders; (2) class cost allocation and rate design; (3) rate case expenses; and (4) fuel and purchased power reconciliation. A. Base rate revenue requirement and riders 12. This Application affects all of ETI’s retail electric customers, and each proposed change is reflected in the proposed revisions to the tariffs that are provided in RFP Schedule Q-8.8. ETI has presented its revenue requirement based on an adjusted twelve-month test year ending on June 30, 2011. The proposed base rates and riders produce an increase of approximately $111.8 million, or 8.09%, over adjusted test year revenues. Excluding fuel costs, the proposed change produces an increase in revenues of approximately 15.32%. Please see Attachment A for the details of how the revenue requirement affects each rate class. 13. The Company’s request includes two new riders for which the Company seeks Commission approval in this case: (a) A Purchased Power Recovery Rider (“Rider PPR”), which is designed to recover all existing purchased capacity costs as well as future purchased capacity costs. As set in this case, Rider PPR will 4 2011 ETI Rate Case 1-4 recover approximately $272.7 million annually. The Company’s request includes (1) a mechanism to update the rider annually to reflect increases or decreases in purchased capacity costs as incurred by the Company, and (2) the reconciliation of costs recovered under the rider in the Company’s fuel reconciliation cases.6 (b) A Renewable Energy Credits Rider (“Rider REC”), which is designed to recover renewable energy credits costs incurred by the Company to comply with PURA § 39.904 and P.U.C. SUBST. R. 25.173. As set in this case, the Rider REC rate will recover approximately $632 thousand. 14. To the extent any of the riders addressed above are not approved, ETI proposes to recover the associated costs through its base rates or other rate mechanism designed to recover non-fuel production-related costs. 15. The Company is not proposing a transmission cost recovery factor or distribution cost recovery factor in this case, but the Company is seeking to establish baseline values for future use when those two riders are implemented. 16. ETI’s Application affects all of its retail customers and all customer classes. The increase in rates by rate class is set out in Attachment A. This application has no effect on the rates of ETI’s wholesale customers. 17. Elements of ETI’s base rate case include the following: (a) ETI is seeking to establish just and reasonable rates that reflect its total revenue requirement, including affiliate transaction payments, non-affiliate operations and maintenance expenses, federal income tax expense, expenses for taxes other than income, depreciation and amortization expense, and an authorized rate of return that reflects a 10.6% return on common equity. The 6 The Company proposes that expenses eligible for reconciliation under Rider PPR also include credits for Interruptible Service and Competitive Generation Service (“CGS”) unrecovered costs, as well as fixed charges associated with Toledo Bend and the Southwest Power Pool Reserve Sharing Group. 5 2011 ETI Rate Case 1-5 Company is also seeking to replenish its property insurance reserve. (b) ETI proposes a number of pro forma adjustments to its test year results, as explained in the direct testimony of Company witnesses. (c) ETI is seeking to include in rate base capital additions closed to plant in service from July 1, 2009 through the end of the test year. (d) In regard to affiliate transactions, ETI has divided its affiliate payments into classes of service and is presenting testimony and documentary evidence (e.g., discussion of budgeting and cost control efforts, benchmarking results as available, review of the costs of major components for each class, and headcount and historical cost trends) for each class, demonstrating that the affiliate transaction payments satisfy the standard for recovery set out in PURA § 36.058. The prefiled direct testimony of ETI witness Stephanie B. Tumminello explains how the evidence supporting affiliate payments is organized. 18. To summarize, ETI’s filing proposes that the Commission establish the Company’s revenue requirement as set out in the Rate Filing Package, including a determination that the Company has satisfied PURA’s standards for recovery of affiliate costs. ETI further requests that the Commission approve its proposed rate riders, and ETI seeks good cause exceptions to the extent necessary to comply with the Commission’s rules. B. Class cost allocation and rate design 19. ETI’s filing also addresses cost allocation and rate design. This includes: (1) inter- and intra-class cost allocation, (2) rate design, and (3) the tariff schedules in RFP Schedule Q-8.8. The Company is proposing revisions to its tariffs and rate schedules, including making modifications to eleven schedules, adding two new rate schedule riders, and discontinuing two riders. The Company also proposes minor modifications to a number of rate schedules, 6 2011 ETI Rate Case 1-6 which are detailed in the tariff manual on file with the Commission and each municipality exercising original jurisdiction over Entergy Texas’ rates. 20. The eliminated rate schedule is: Schedule Description Rider RPSCOC Renewable Portfolio Standard Calculation Opt-Out Credit Rider 21. The Company is proposing to make modifications to the following rate schedules: Schedule Description MES Miscellaneous Electric Services SMC Special Minimum Charge Rider to Schedules SGS, GS and LGS ALS Area Lighting Service AFC Additional Facilities Charges Rider SQF Rate for purchases From Qualifying Facilities Less Than Or Equal to 100 KW Distributed Generators GS General Service GS-TOD General Service-Time of Day LGS Large General Service LGS_TOD Large General Service-Time of Day LIPS Large Industrial Power Service LIPS-TOD Large Industrial Power Service-Time of Day IS Rider to Schedule LIPS for Interruptible Service Agreement for Additional Facilities DTK Agreement for Installation for Interval Data Recorder Equipment Agreement for Electric Service Terms and Conditions Applicable for Electric Service 22. In addition to the revenue requirement outlined in ¶ 12 above, Schedule MES revenues will increase by approximately $911,000 as a result of the proposed revisions to this rate schedule. 7 2011 ETI Rate Case 1-7 23. The new rate schedules/riders are: (a) Rider PPR (b) Rider REC 24. In addition, the production costs associated with the Company’s CGS program will change as a result of this proceeding. 25. Consistent with the final order in ETI’s last rate case, Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744, the life-of-contract demand ratchet provision in rate schedules Large Industrial Power Service, Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day, Large General Service, and Large General Service-Time of Day shall be excluded from those rate schedules. C. Rate case expenses 26. ETI’s filing also addresses rate case expenses. ETI is seeking to recover its rate case expenses associated with this docket and any rate case expenses associated with this docket that it must reimburse to local regulatory authorities. D. Fuel and purchased power reconciliation 27. Pursuant to P.U.C. SUBST. R. 25.236, ETI seeks reconciliation of its fuel and purchased power costs and fuel factor revenues for the Reconciliation Period. This Application will affect all of ETI’s retail customers taking service under its fixed fuel factor (“Schedule FF”) by reconciling the fuel and purchased power costs incurred and the fuel factor revenues received in providing service to these customers during the Reconciliation Period. 28. During the Reconciliation Period, ETI incurred over $1.3 billion in retail eligible fuel and purchased power expenses to generate and purchase electricity, net of certain revenues properly credited to such expenses and other adjustments. The following tables summarize the calculation, by fuel type, of ETI’s total eligible fuel and purchased power costs to be reconciled in this proceeding: 8 2011 ETI Rate Case 1-8 Gas and Oil $ 616,248,686 Emissions Allowances 360,236 Coal* 90,821,317 Total Fuel: $ 707,430,239 Purchased Power Expense 990,041,434 Off System Sales Revenues (376,671,969) Total Purchased Power: 613,369,465 Total Texas Jurisdictional Fuel Factor Cost:** $ 1,320,799,704 Over-recovery Balance: $ 243,339,353 Sources: Schedules I-16, H-12.4a-g, H-12.5b-e, I-22, and Direct Testimonies of Margaret L. McCloskey and Greg R. Zakrzewski. *Includes cost of oil burned for start-up and flame stabilization. **Amounts may not tie to Schedules due to rounding. 29. ETI’s reconciliation includes interest expense on any over/under- recovery balance. ETI does not seek to implement a refund or surcharge of eligible fuel or purchased power costs at the conclusion of this case; rather, ETI proposes to roll any ending fuel balances forward to serve as the beginning balance for the next Reconciliation Period. 30. The Company seeks a special circumstances finding to recover as fuel expense the reversal of a prior FERC-ordered credit in the amount of $99,715 that was previously included in the Company’s Incremental Purchased Capacity Recovery Rider (“Rider IPCR”). The credit related to a FERC proceeding that required the removal of interruptible load from the calculation of each Operating Company’s responsibility ratio, resulting in ETI receiving a credit for capacity costs incurred in 2008 that were included in Rider IPCR at that time. FERC has since reversed its prior position and required the Company to refund this amount to the other Operating Companies. Louisiana Public Service Corp. et al. v. Entergy Corp., 135 FERC ¶ 61,218 (2011). Federal law requires that such a FERC-ordered refund be passed through to retail customers. Id. at P 6. The Company seeks a special circumstances finding to treat the repayment to the other Operating Companies as fuel expense to be consistent with a settlement approved in Docket No. 37744, which treated the residual Rider IPCR balance as fuel expense. Application of Entergy Texas, Inc., for Authority 9 2011 ETI Rate Case 1-9 to Change Rates and Reconcile Fuel Costs, Docket No. 37744, Final Order at FoF 30 (Dec. 13, 2010). ETI seeks the same treatment in this case because the repayment is a residual amount of Rider IPCR costs, except that ETI proposes to allocate the costs among customer classes on an energy basis in light of the nominal amount. 31. ETI’s Rate Filing Package demonstrates that: (1) ETI’s fuel and purchased power expenses were reasonable and necessary expenses incurred to provide reliable electric service; and (2) to the extent fuel and purchased power expenses included an item or class of items supplied by an affiliate of ETI, the price charged by the affiliate satisfies the standard for recovery set out in PURA § 36.058. V. Notice 32. ETI will provide notice in accordance with PURA § 36.103, P.U.C. PROC. R. 22.51(a), and P.U.C. SUBST. R. 25.235. The proposed notice is provided as Attachment B to this Application. VI. Municipal Filings 33. Simultaneously with filing this Application with the Commission, ETI is filing a Statement of Intent to change its rates with all local regulatory authorities that retain jurisdiction over ETI’s rates to the extent consistent with the provisions of PURA. Depending on the actions taken by the local regulatory authorities, ETI may appeal the municipal rate ordinances to the Commission and request that the Commission consolidate those appeals with this docket and, if necessary, set the rates that the local regulatory authorities should have set, pursuant to PURA § 33.054. VII. Request for Waiver of Rate Filing Package Requirements 34. For the reasons stated in RFP Schedule V, ETI requests that the Commission waive certain Rate Filing Package filing requirements. 10 2011 ETI Rate Case 1-10 VIII. Confidentiality Provisions 35. Certain of ETI’s fuel and purchased power contracts contain provisions that require the Company to maintain the confidentiality of these contracts and data related to these contracts. In addition, certain information required by the Commission’s Rate Filing Package consists of proprietary, market-sensitive information that is confidential or highly sensitive data or that unaffiliated third parties have provided to the Company under agreements restricting dissemination. Finally, certain components of and documents included in ETI’s prefiled direct testimony and/or workpapers include confidential and/or highly sensitive information. 36. To facilitate evaluation of this information by the Commission Staff and other parties, the Company has prepared a Protective Order that is contained in RFP Schedule W. ETI requests that the Protective Order (Schedule W) be adopted for use in this proceeding. 37. Attachment C to this Application presents a complete listing of the information required to be filed in the Commission’s Rate Filing Package that the Company designates as confidential or highly sensitive. Pending issuance of a Protective Order in this case, the confidential or highly sensitive information will be made available at the Company’s offices, 919 Congress Avenue, Suite 840, Austin, Texas 78701, telephone number (512) 487-3999, during normal business hours to parties who execute a confidentiality disclosure agreement. IX. Conclusion and Request for Relief For the reasons set out in this Application, the accompanying direct testimony, and the Rate Filing Package, ETI requests that the Commission: (1) grant the requested relief to the full extent of the Commission’s jurisdiction; (2) find that notice of this filing be considered sufficient; and (3) grant ETI such other relief that it is entitled to receive. Dated: November 28, 2011. 11 2011 ETI Rate Case 1-11 Respectfully submitted, Steven H. Neinast Paula Cyr Assistants General Counsel ENTERGY SERVICES, INC. 919 Congress Avenue, Suite 701 Austin, Texas 78701 (512) 487-3957 telephone (512) 487-3958 facsimile DUGGINS WREN MANN & ROMERO, LLP One American Center 600 Congress, Suite 1900 P.O. Box 1149 Austin, Texas 78767-1149 (512) 744-9300 telephone (512) 744-9399 facsimile John F. Williams Jay Breedveld 12 2011 ETI Rate Case 1-12 ATTACHMENT A ENTERGY TEXAS, INC. INCREASE BY RATE CLASS WITH RIDERS FOR THE TWELVE MONTHS ENDING JUNE 30, 2011 Number of Base Revenue Percent Customers Present Present Total Proposed Proposed Proposed Proposed Total Change To and Riders Change Test Year Base Rate Rider Present Present Base Rate Rider PPR Rider REC Rider Proposed Proposed Total Percent Total 2011 ETI Rate Case Rate Class Adjusted Revenue Revenue (1) Fuel Revenue Revenue Revenue (1) Revenue Revenue Fuel Revenue Revenue Change Revenues (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (g)+(h)+(i) (c)+(d)+(e) +(j)+(k) (l)-(f) (m)]/((c)+(d)) (m)/(f) Residential Service 359,707 $ 325,744,455 $ 53,637,192 $ 232,546,816 $ 611,928,463 $ 271,808,430 $ 53,637,192 $ 135,702,041 $ 329,063 $ 232,546,816 $ 694,023,542 $ 82,095,079 21.64% 13.42% Small General Service 30,998 $ 22,562,013 $ 3,867,520 $ 12,957,514 $ 39,387,047 $ 16,969,307 $ 3,867,520 $ 6,003,125 $ 18,335 $ 12,957,514 $ 39,815,801 $ 428,754 1.62% 1.09% General Service 19,156 $ 135,404,167 $ 24,363,668 $ 135,331,429 $ 295,099,264 $ 91,350,968 $ 24,363,668 $ 51,554,797 $ 188,900 $ 135,331,429 $ 302,789,762 $ 7,690,498 4.81% 2.61% Large General Service 361 $ 42,430,160 $ 6,949,815 $ 62,652,322 $ 112,032,297 $ 30,269,687 $ 6,949,815 $ 20,247,492 $ 84,677 $ 62,652,322 $ 120,203,993 $ 8,171,696 16.55% 7.29% Large Industrial Power Service 82 $ 100,482,959 $ 3,825,264 $ 204,909,461 $ 309,217,684 $ 53,366,022 $ 3,825,264 $ 58,342,383 $ 8,451 $ 204,909,461 $ 320,451,581 $ 11,233,897 10.77% 3.63% Lighting Service 1,689 $ 7,490,488 $ 3,322,394 $ 3,222,163 $ 14,035,045 $ 8,860,430 $ 3,322,394 $ 829,439 $ 4,559 $ 3,222,163 $ 16,238,985 $ 2,203,940 20.38% 15.70% Total Retail (2) 411,993 $ 634,114,242 $ 95,965,853 $ 651,619,705 $ 1,381,699,800 $ 472,624,844 $ 95,965,853 $ 272,679,277 $ 633,985 $ 651,619,705 $ 1,493,523,664 $ 111,823,864 15.32% 8.09% (1) Riders: TTC, HRC, EECRF, RCE, IS, SRC & SCO which are the same for present and proposed (2) Excludes EAPS and SMS 1-13 Sponsor: Joseph F. Domino Docket No. 39896 Entergy Texas’s Statement of Intent and Application Attachment B Schedule T Page 1 of 3 NOTICE OF RATE CHANGE REQUEST On November 28, 2011, Entergy Texas, Inc. (“Entergy Texas”) filed its STATEMENT OF INTENT AND APPLICATION FOR AUTHORITY TO CHANGE RATES AND RECONCILE FUEL COSTS (“Application”). Entergy Texas filed its Application with the Public Utility Commission of Texas (“Commission”) and with those municipal authorities in its service territory that have original jurisdiction over Entergy Texas’ electric rates. Statement of Intent to Change Rates and to Reconcile Fuel Costs Entergy Texas’ filing requests an increase in rates, addresses capital additions to rate base for the period July 2009 through June 2011, requests that the Commission reconcile fuel and purchased power expenses incurred during the period July 2009 through June 2011 (“Reconciliation Period”), and requests approval of a number of tariffs, cost recovery schedules and riders. In its Application, Entergy Texas is, among other things: x Proposing base rate tariffs and riders designed to collect a total non-fuel retail revenue requirement for ETI of approximately $841.9 million per year, which is an increase of $111.8 million, or 15.32%, compared to adjusted retail base rate and rider revenues resulting from the Commission’s Order in Docket No. 37744. The Company’s proposed rate increase is based on the test year period of July 1, 2010 through June 30, 2011. This proposal represents an increase in overall revenues, including fuel, of 8.09%. x Asking to reconcile fuel and purchased power costs of approximately $1.3 billion incurred during the Reconciliation Period. The reconciliation includes interest on any over- or (under)-recovered amounts. Entergy Texas does not seek to implement a fuel-related refund or surcharge of its eligible fuel costs in this case; rather, ETI proposes to roll any ending fuel balances forward to serve as the beginning balance for the next Reconciliation Period. Tariff Revisions Entergy Texas is proposing to add two new rate schedules or riders as follows: o A Purchased Power Recovery Rider (“Rider PPR”), which is designed to recover all existing purchased capacity costs as well as future purchased capacity costs. As set in this case, Rider PPR will recover approximately $272.7 million annually. ETI’s request 2011 ETI Rate Case 1-14 Sponsor: Joseph F. Domino Docket No. 39896 Entergy Texas’s Statement of Intent and Application Attachment B Schedule T Page 2 of 3 includes (1) a mechanism to update the rider annually to reflect increases or decreases in purchased capacity costs as incurred by the Company, and (2) the reconciliation of costs recovered under the rider in the Company’s fuel reconciliation cases. The Company proposes that expenses eligible for reconciliation under Rider PPR also include credits for Interruptible Service and Competitive Generation Service unrecovered costs, as well as fixed charges associated with Toledo Bend and the Southwest Power Pool Reserve Sharing Group. o A Renewable Energy Credits Rider (“Rider REC”), which is designed to recover renewable energy credits costs and related costs incurred by the Company to comply with PURA § 39.904 and P.U.C. Subst. R. 25.173. As set in this case, the Rider REC rate will recover approximately $632 thousand. To the extent any of the riders described above are not approved, Entergy Texas proposes to recover the associated costs through its base rates or other rate mechanism designed to recover non-fuel production-related costs, though the overall non-fuel revenue increase referenced above will remain the same. In addition, Entergy Texas is proposing to establish baseline values to use if a transmission cost recovery factor or distribution cost recovery factor are implemented in the future. In addition, Entergy Texas is proposing to modify terms and charges in a number of its tariff schedules and to discontinue its Renewable Portfolio Standard Calculation Opt-Out Credit Rider. Proposed changes to Schedule Miscellaneous Electric Service (“MES”) will increase revenues by approximately $911,000 in addition to the retail revenue requirement stated above. The production costs associated with the Company’s proposed Competitive Generation Service program will also change as a result of this proceeding. Entergy Texas also proposes minor modifications to a number of rate schedules, which are detailed in the tariff manual on file with the Commission and each municipality exercising original jurisdiction over Entergy Texas’ rates. Effect on Customer Classes All customers and classes of customers receiving retail electric service from Entergy Texas will be affected by the proposed rate changes and reconciliation of fuel and purchased power costs contained in the Application. The following table shows the effect of the proposed rate increase (inclusive of riders but exclusive of the increase in Schedule MES revenues) on existing rate classes: 2011 ETI Rate Case 1-15 Sponsor: Joseph F. Domino Docket No. 39896 Entergy Texas’s Statement of Intent and Application Attachment B Schedule T Page 3 of 3 Number of Percent Change Customers Test in Non-Fuel Percent Change in Rate Class Year Adjusted Revenues Total Revenues* Residential Service 359,707 21.64% 13.42% Small General Service 30,998 1.62% 1.09% General Service 19,156 4.81% 2.61% Large General Service 361 16.55% 7.29% Large Industrial Power Service 82 10.77% 3.63% Lighting Service 1,689 20.38% 15.70% Total Retail 411,993 15.32% 8.09% * including fuel revenues The effective date of the rate change is January 2, 2012. Contact Information Persons with questions or who want more information on this filing may contact Entergy Texas at Entergy Texas, Inc., Attn: Customer Service—2011 Rate Case, 350 Pine Street, Beaumont, Texas 77701, or call [1-800-368-3749 (select option 1, then press 0, then press 4, then press 3)] during normal business hours. A complete copy of this application is available for inspection at the address listed above. Persons who wish to intervene in or comment upon these proceedings should notify the Public Utility Commission of Texas as soon as possible, as an intervention deadline will be imposed. A request to intervene or for further information should be mailed to the Public Utility Commission of Texas, P.O. Box 13326, Austin, Texas 78711-3326. Further information may also be obtained by calling the Public Utility Commission at (512) 936-7120 or (888) 782-8477. Hearing- and speech-impaired individuals with text telephones (TTY) may contact the commission at (512) 936-7136. The deadline for intervention in this proceeding is 45 days after the date the application was filed with the Commission. All communications should refer to Docket No. 39896. 2011 ETI Rate Case 1-16 Application Attachment C 2011 Texas Rate Case Page 1 of 4 List of Confidential (Protected Material)/ Highly Sensitive (Highly Sensitive Protected Material) Information The following is a list of schedules, exhibits and workpapers that are included in this Application and considered by Entergy Texas, Inc. (“the Company”) to be Confidential (Protected Material) or Highly Sensitive (Highly Sensitive Protected Material) information, the protected designation, the reason for protection and a list of the witnesses sponsoring the Confidential (Protected Material) or Highly Sensitive (Highly Sensitive Protected Material) information or the schedule to which the information relates. The Company considers the information listed below to be commercial or financial information or customer specific information that is exempted from disclosure under the Public Information Act. TEX. GOV’T CODE ANN. §§ 552.101 and 552.110 (Vernon 2009); TEX. UTIL. CODE § 32.101(c) (Vernon 2009). DOCUMENT DESIGNATION REASON FOR SPONSOR PROTECTION Rate Filing Package Schedule B-2 Highly Sensitive Proprietary Information Considine, Michael P. WP/E-2.2 Attachment 3 Highly Sensitive Proprietary Information Trushenski, Ryan S.; McIlvoy, Karen D.; Considine, Michael P. WP/E-2.2 Attachment 4 Highly Sensitive Proprietary Information Trushenski, Ryan S.; McIlvoy, Karen D.; Considine, Michael P. Schedule G-5.1 Confidential Proprietary Information Considine, Michael P. Schedule G-5.1a Confidential Proprietary Information Considine, Michael P. Schedule G-7.3 Highly Sensitive Proprietary Information Roberts, Rory L. WP/G-7.3 Highly Sensitive Proprietary Information Roberts, Rory L. WP/G-7.13 Highly Sensitive Proprietary Information Roberts, Rory L.; Considine, Michael P. Schedule H-5.3b Confidential Proprietary Information Garrison, W. Wayne Schedule H-6.2c Confidential Proprietary Information Garrison, W. Wayne Schedule H-7.2 Confidential Proprietary Information Garrison, W. Wayne Schedule H-7.4 Confidential Staffing Projections Garrison, W. Wayne Schedule H-12.3c Confidential Proprietary Information Garrison, W. Wayne Schedule H-13.2 Highly Sensitive Proprietary Information McCulla, Mark 2011 ETI Rate Case 1-17 Application Attachment C 2011 Texas Rate Case Page 2 of 4 Schedule I-1.2 Highly Sensitive Contractual/Proprietary Jaycox, Devon S.; Information Zakrzewski, Gregory R.; Trushenski, Ryan S.; McIlvoy, Karen D.; Thiry, Michelle H. Schedule I-4 Confidential/Highly Contractual/Proprietary Cooper, Robert R.; Sensitive Information Thiry, Michelle, H. McIlvoy, Karen D.; Trushenski, Ryan S. WP/I-4 Confidential/Highly Contractual/Proprietary Cooper, Robert R.; Sensitive Information Thiry, Michelle, H. McIlvoy, Karen D.; Trushenski, Ryan S. Schedule I-15 Confidential Contractual/Proprietary Cooper, Robert R.; Information Trushenski, Ryan S.; McIlvoy, Karen D.; Thiry, Michelle H. WP/I-15 Confidential/Highly Contractual/Proprietary Cooper, Robert R.; Sensitive Information Trushenski, Ryan S.; McIlvoy, Karen D.; Thiry, Michelle H. Schedule I-16 Highly Sensitive Contractual/Proprietary Trushenski, Ryan S.; Information McIlvoy, Karen D.; Zakrzewski, Gregory R. Schedule I-16.3 Highly Sensitive Contractual/Proprietary Trushenski, Ryan S.; Information McIlvoy, Karen D. Schedule I-17.1 Highly Sensitive Contractual/Proprietary Trushenski, Ryan S.; Information Zakrzewski, Gregory R. WP/I-21 Confidential Financial Forecasts Thiry, Michelle H. Schedule K-5 Highly Sensitive Financial Forecasts Barrilleaux, Chris E.; Considine, Michael P. Schedule K-6 Highly Sensitive Financial Forecasts Barrilleaux, Chris E. ; Considine, Michael P. Schedule K-7 Highly Sensitive Financial Forecasts Barrilleaux, Chris E. Schedule M-1 Confidential Contractual/Proprietary Considine, Michael P. Attachment 1 Information Schedule M-1 Confidential Contractual/Proprietary Considine, Michael P. Attachment 3 Information Schedule M-1 Confidential Proprietary Information Considine, Michael P. Attachment 6 Schedule M-1 Confidential Contractual/Proprietary Considine, Michael P. Attachment 7 Information WP2/M-2 Confidential Contractual/Proprietary Considine, Michael P. Information Schedule Q-8.1 Highly Sensitive Financial Forecasts Cicio, Patrick J. Schedule Q-8.2 Highly Sensitive Financial Jaycox, Devon S. Forecasts/Proprietary Information 2011 ETI Rate Case 1-18 Application Attachment C 2011 Texas Rate Case Page 3 of 4 Schedule Q-8.3 Highly Sensitive Proprietary Information Cooper, Robert R. Schedule Q-8.4 Highly Sensitive Staffing Cooper, Robert R. Projections/Proprietary Information Schedule S-2 Highly Sensitive Proprietary Information NA Testimonial Exhibits and Workpapers (Listed in order by sponsor) Testimony pp. 10-12, Highly Sensitive Competitive Information Barrilleaux, Chris E. 14-15, 26 and 28 WP/CEB Testimony 1 Highly Sensitive Competitive Information Barrilleaux, Chris E. WP/CEB Testimony 2 Highly Sensitive Competitive Information Barrilleaux, Chris E. WP/CEB Testimony 3 Highly Sensitive Competitive Information Barrilleaux, Chris E. Exhibit RRC-1 Highly Sensitive Proprietary/Commercially Cooper, Robert R. Sensitive Information WP/RRC Testimony 2 Highly Sensitive Proprietary/Commercially Cooper, Robert R. Sensitive Information Exhibit KGG-4 Highly Sensitive Compensation Information Gardner, Kevin G. Exhibit KGG-5 Highly Sensitive Compensation Information Gardner, Kevin G. Exhibit CNH-9 Confidential Proprietary Information Herrington, Chester N. Exhibit CNH-12 Confidential Proprietary Information Herrington, Chester N. Exhibit JMH-4 Confidential Competitively Sensitive Hunter, Joseph M. WP/JJJ-3 Confidential Competitively Sensitive Joyce, Jay J. Contractual/Proprietary Information Compensation Information WP/KDM Testimony Highly Sensitive Proprietary Gas Contract McIlvoy, Karen D. Pricing Information Exhibit RLR-5 Highly Sensitive Proprietary Information Roberts, Rory L. Exhibit RLR-6 Highly Sensitive Proprietary Information Roberts, Rory L. WP/RDS Testimony Highly Sensitive Proprietary Information Sloan, Robert D. WP/MHT Testimony 1 Highly Sensitive Proprietary/Trade Thiry, Michelle H. Information WP/MHT Testimony 2 Highly Sensitive Proprietary/Trade Thiry, Michelle H. Information WP/GSW-2 Highly Sensitive Proprietary Information Wilson, Greg S. 2011 ETI Rate Case 1-19 Application Attachment C 2011 Texas Rate Case Page 4 of 4 I certify that I have reviewed the documents listed above and state in good faith that the information is exempt from public disclosure under the Public Information Act and merits the applicable designation of Confidential (Protected) Materials or Highly Sensitive (Highly Sensitive Protected) Materials detailed in the Protective Order accompanying this Application. ~~~ 2011 ETI Rate Case 1-20 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 ETI 2011 Rate Case ETI EXHIBIT NO. 8 DOCKET NO. 39896 APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION TEXAS, INC. FOR AUTHORITY § TO CHANGE RATES AND § OF TEXAS RECONCILE FUEL COSTS § DIRECT TESTIMONY OF MICHAEL P. CONSIDINE ON BEHALF OF ENTERGY TEXAS, INC. NOVEMBER 2011 2011 ETI Rate Case 3-279 ENTERGY TEXAS, INC. DIRECT TESTIMONY OF MICHAEL P. CONSIDINE 2011 RATE CASE TABLE OF CONTENTS Page I. Witness Introduction and Qualifications 1 II. Purpose of Testimony 2 III. PURA Sections 36.059 through 36.062 4 A. Section 36.059 – Treatment of Certain Tax Benefits 5 B. Section 36.061 – Allowance of Certain Expenses and Section 36.062 – Consideration of Certain Expenses 6 1. Legislative Advocacy Expenses 6 2. Charitable Contributions 7 3. Outside Services 7 4. Rate Case Expenses 8 5. Civil Penalties and Fines 8 6. Disallowed Payments for Costs of Facilities not Selling Power in the State of Texas 8 7. Costs of Processing Refunds or Credits 9 IV. PUC Substantive Rule 25.231(b) 9 V. Cost of Service 11 A. Schedule A – Overall Cost of Service 11 1. Adjustments 13 a) Local Franchise Tax Adjustment (Adjustment 7) 15 b) Property Insurance Reserve (Adjustment 8) 15 c) Margins Tax (Adjustment 9) 16 d) Income Taxes (Adjustment 10) 16 2011 ETI Rate Case 3-280 e) Rate Case Expense (Adjustment 11) 18 f) Trade Association Dues/Legislative Advocacy (Adjustment 12) 18 g) Depreciation Expense (Adjustment 13) 19 h) Depreciation Study Adjustment (Adjustment 14) 19 i) Hurricane Securitization (Adjustment 15) 20 j) Miscellaneous Adjustments (Adjustment 16) 21 k) Interest Synchronization (Adjustment 17) 22 l) Customer Deposits and ESI Interest Expense (Adjustment 18) 22 m) SFAS 106 (Adjustment 19) 23 n) Pension Expense (Adjustment 20) 24 o) Payroll Expense (Adjustment 22) 24 p) Service Schedule MSS-2 Adjustment (Adjustment 23) 25 q) Capacity Adjustment (Adjustment 24) 25 r) Property Tax (Adjustment 25) 26 2. Trial Balances, Schedule A-4 26 B. Schedule B - Rate Base and Return 27 1. Rate Base Adjustments 27 a) Cash Working Capital (Adjustment 6) 27 b) Income Tax (Adjustment 10) 28 2. Schedules B-1.1 through B-2.1 28 C. Schedule C – Original Cost of Plant 29 D. Schedule D – Accumulated Depreciation 31 E. Schedule E – Short-Term Assets and Inventories 33 2011 ETI Rate Case 3-281 F. Schedule G – Accounting Information 35 1. Payroll Schedules 35 2. Pensions and Benefits Schedules 37 3. Bad Debt Expense Schedule 38 4. Advertising, Contributions, and Dues Schedules 38 5. Exclusions from Test Period Schedules 40 6. Income Tax Schedules 41 7. Outside Services Schedule 49 8. Taxes Other Than Income Tax Schedules 50 9. Factoring Expense Schedule 50 10. Deferred Expense Information Schedule 50 11. Below the Line Expenses Schedule 51 12. Non-Recurring Expense Schedule 51 13. Rate Case Expense Schedules 52 14. Monthly O&M Schedules 52 G. Schedule H – Engineering Information 53 H. Schedule J – Financial Statements 54 I. Schedule K – Financial Information 55 J. Schedule M – Nuclear Plant Decommissioning 57 K. Schedule P – Class Cost of Service Analysis 58 L. Schedule S – Test Year Review 58 VI. Rate Case Expenses 60 VII. Conclusion 62 2011 ETI Rate Case 3-282 EXHIBITS Exhibit MPC-1 Listing of Rate Filing Packages Schedules Sponsored or Co-Sponsored by Michael P. Considine Exhibit MPC-2 Nuclear Regulatory Commission Letter dated August 9, 2011 2011 ETI Rate Case 3-283 Entergy Texas, Inc. Page 1 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 I. WITNESS INTRODUCTION AND QUALIFICATIONS 2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 3 A. My name is Michael P. Considine. My business address is 425 West 4 Capitol Avenue, Little Rock, Arkansas 72201. I am employed by Entergy 5 Services, Inc., the service company affiliate of Entergy Texas, Inc. (“ETI” 6 or the “Company”) as a Senior Staff Accountant in the Rate Design and 7 Administration Department. 8 9 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? 10 A. I am testifying on behalf of Entergy Texas, Inc. (“ETI” or the “Company”). 11 12 Q. DESCRIBE BRIEFLY YOUR EDUCATIONAL BACKGROUND AND 13 PROFESSIONAL EXPERIENCE. 14 A. I received a Bachelor of Science Degree in Professional Accountancy 15 from Louisiana Tech University in 2000. I began my career with Alltel 16 Communications, first as an accountant in the general accounting 17 department, and then as a financial analyst in the financial planning 18 department. In October 2001, I accepted a position as an analyst in the 19 Transmission Business Operations department of Entergy Services, Inc. 20 In this regard, I was responsible for Open Access Transmission Tariff 21 (“OATT”) monthly billings and the development of enhanced billing 22 processes for OATT customers. I transferred to the Rate Design and 2011 ETI Rate Case 3-284 Entergy Texas, Inc. Page 2 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Administration Department in September 2003. In December 2010, I 2 accepted my current position in the Regulatory Accounting Department. 3 4 Q. WHAT ARE YOUR PRINCIPAL AREAS OF RESPONSIBILITY? 5 A. I provide general regulatory support, including the analysis and 6 development of rate design and external allocation factors for use in cost- 7 of-service analyses, for Entergy’s six Operating Companies (Entergy 8 Arkansas, Inc.; Entergy Gulf States Louisiana, L.L.C.; Entergy Louisiana, 9 LLC; Entergy Mississippi, Inc.; Entergy New Orleans, Inc.; and ETI). I am 10 also responsible for preparation and filing of the Company’s monthly Fuel 11 Reports with the Public Utility Commission of Texas (the “Commission”), 12 including the calculation of the monthly over(under)-recovery of fuel 13 expenses. 14 15 II. PURPOSE OF TESTIMONY 16 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 17 A. The purpose of my testimony is to support the Company's per books test 18 year accounting data, capital structure, and certain pro forma adjustments. 19 In addition, I will present ETI’s regulatory treatment of legislative advocacy 20 expenses, advertising expense, donations and contributions, outside 21 services, income taxes, and dues and memberships. I will also address 22 rate case expenses. 2011 ETI Rate Case 3-285 Entergy Texas, Inc. Page 3 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. WHAT TEST YEAR DOES ETI USE IN THIS FILING? 2 A. This filing uses the twelve months ended June 30, 2011. 3 4 Q. DO YOU SPONSOR OR CO-SPONSOR ANY SCHEDULES IN THE 5 RATE FILING PACKAGE (“RFP”) THAT HAVE BEEN FILED IN THIS 6 PROCEEDING? 7 A. Yes, I sponsor or co-sponsor several schedules filed in this proceeding. 8 Exhibit MPC-1 indicates the schedules that I am sponsoring or 9 co-sponsoring with other witnesses. In addition, for convenience, Exhibit 10 MPC-1 shows the titles of all the schedules that I discuss in my testimony. 11 Unless otherwise indicated, the schedules were prepared by me or under 12 my direct supervision and control. 13 14 Q. ON WHAT BASIS WERE THE SCHEDULES THAT YOU JUST 15 MENTIONED PREPARED? 16 A. They were prepared from the books and records of the Company and are 17 accurate summaries of the business records upon which they are based. 18 The schedules have been examined by Deloitte & Touche, our 19 independent auditors. The report of their examination is included in 20 Schedule S of the RFP. 2011 ETI Rate Case 3-286 Entergy Texas, Inc. Page 4 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. ARE THE BOOKS, ACCOUNTS, AND RECORDS OF THE COMPANY 2 MAINTAINED IN A MANNER PRESCRIBED BY THE COMMISSION? 3 A. Yes, they are kept in compliance with the FERC Uniform System of 4 Accounts as prescribed in Section 14.151 of the Public Utility Regulatory 5 Act (“PURA”), and in P.U.C. SUBST. R. 25.72(b)(1), (c)(1), and (e) 6 through (g). The records are maintained in New Orleans, Louisiana as 7 approved by this Commission in Docket No. 13017. 8 9 III. PURA SECTIONS 36.059 THROUGH 36.062 10 Q. SECTIONS 36.059 THROUGH 36.062 OF PURA PROVIDE FOR 11 SPECIFIC TREATMENT OR EXCLUSION OF CERTAIN ITEMS FOR 12 RATEMAKING PURPOSES. DOES THE COMPANY'S FILING COMPLY 13 WITH THESE SECTIONS OF PURA? 14 A. Yes. ETI has fully complied with PURA Sections 36.059 through 36.062. 15 This filing includes only reasonable and necessary costs that are allowed 16 under PURA, and excludes any costs specifically prohibited. Company 17 witness Rory L. Roberts discusses PURA Section 36.060 (consolidated 18 income tax returns) in his testimony. The following discussion addresses 19 the items specifically set out in Sections 36.059, 36.061, and 36.062 of 20 PURA. 2011 ETI Rate Case 3-287 Entergy Texas, Inc. Page 5 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 A. Section 36.059 – Treatment of Certain Tax Benefits 2 Q. HAS THE COMPANY COMPLIED WITH THE TREATMENT OF TAX 3 BENEFITS AS REQUIRED BY SECTION 36.059? 4 A. Yes. Section 36.059 requires: 5 (a) In determining the allocation of tax savings derived from 6 liberalized depreciation and amortization, the investment tax 7 credit, and the application of similar methods, the regulatory 8 authority shall: 9 (1) balance equitably the interests of present and future 10 customers; and 11 12 (2) apportion accordingly the benefits between 13 consumers and the electric or municipally owned 14 utility. 15 16 (b) If an electric utility or a municipally owned utility retains a 17 portion of the investment tax credit, that portion shall be 18 deducted from the original cost of the facilities or other 19 addition to the rate base to which the credit applied to the 20 extent allowed by the Internal Revenue Code. 21 ETI has computed its cost of service in compliance with this 22 provision of PURA and has applied the investment tax credit (“ITC”) 23 balances to the extent allowed by the Internal Revenue Code (“Code”). 24 RFP Schedule G-7.5, Analysis of ITC, illustrates that the Company is 25 amortizing its ITC no more rapidly than ratably, as required by the Code. 2011 ETI Rate Case 3-288 Entergy Texas, Inc. Page 6 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 B. Section 36.061 – Allowance of Certain Expenses and Section 36.062 – 2 Consideration of Certain Expenses 3 1. Legislative Advocacy Expenses 4 Q. PURA PROVIDES THAT LEGISLATIVE ADVOCACY EXPENSES ARE 5 NOT TO BE INCLUDED IN COST OF SERVICE FOR RATEMAKING 6 PURPOSES. DOES THIS FILING INCLUDE LEGISLATIVE ADVOCACY 7 EXPENSES? 8 A. No. All expenditures made by ETI for the purposes of advocating the 9 Company's position to the public with respect to referenda, legislation, or 10 ordinances, or for the purpose of advocating its position on such items 11 before public officials, are excluded from cost of service. The excluded 12 expenses include the costs of the Company lobbyists, as well as the 13 portion of the Company's dues to the Edison Electric Institute (“EEI”) that 14 are used for legislative advocacy purposes. The legislative expenses 15 associated with EEI and the quantification of the EEI dues excluded are 16 addressed later in my testimony. The expenses, other than the EEI dues 17 described above, are recorded in Account 426.4, which is a non-operating 18 expense account (below the line) that is not included in cost of service. 2011 ETI Rate Case 3-289 Entergy Texas, Inc. Page 7 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. ARE THERE ANY LEGISLATIVE ADVOCACY EXPENSES INCLUDED IN 2 PAYMENTS TO AFFILIATED INTERESTS IN THE COMPANY'S 3 REQUESTED COST OF SERVICE? 4 A. No. Although expenses for legislative advocacy are included in the billings 5 from ESI, such expenses have been excluded from ETI's requested cost 6 of service. 7 8 2. Charitable Contributions 9 Q. HAS THE COMPANY INCLUDED CHARITABLE CONTRIBUTIONS IN 10 ITS COST OF SERVICE? 11 A. No. 12 13 3. Outside Services 14 Q. HAS THE COMPANY INCLUDED COSTS FOR OUTSIDE SERVICES IN 15 ITS REQUESTED COST OF SERVICE? 16 A. Yes. Outside services are required for several reasons. Sound business 17 practice and regulatory and legal requirements result in the need for 18 auditing and accounting services. Further, consultants with specialized 19 expertise and outside legal counsel are employed to provide for various 20 specific needs. 2011 ETI Rate Case 3-290 Entergy Texas, Inc. Page 8 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 4. Rate Case Expenses 2 Q. IS THE COMPANY REQUESTING THE INCLUSION IN COST OF 3 SERVICE RATE CASE EXPENSES RELATED TO THIS FILING? 4 A. Yes. As will be discussed later in my testimony, the Company is 5 requesting recovery in cost of service of the rate case expenses 6 associated with this filing. 7 8 5. Civil Penalties and Fines 9 Q. HAS THE COMPANY INCLUDED IN ITS COST OF SERVICE OR RATE 10 BASE ANY CIVIL PENALTIES OR FINES? 11 A. No. These amounts were recorded in non-operating expense accounts 12 (below the line) and are not included in cost of service. 13 14 6. Disallowed Payments for Costs of Facilities 15 not Selling Power in the State of Texas 16 Q. HAS THE COMPANY INCLUDED IN ITS COST OF SERVICE ANY 17 PAYMENTS, EXCEPT THOSE MADE UNDER AN INSURANCE OR 18 RISK-SHARING ARRANGEMENT EXECUTED BEFORE THE DATE OF 19 LOSS, MADE TO COVER COSTS OF AN ACCIDENT, EQUIPMENT 20 FAILURE, OR NEGLIGENCE AT A UTILITY FACILITY OWNED BY A 21 PERSON OR GOVERNMENTAL BODY NOT SELLING POWER INSIDE 22 THE STATE OF TEXAS? 23 A. No. 2011 ETI Rate Case 3-291 Entergy Texas, Inc. Page 9 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 7. Costs of Processing Refunds or Credits 2 Q. HAS THE COMPANY INCLUDED IN ITS COST OF SERVICE ANY COST 3 OF PROCESSING A REFUND OR CREDIT UNDER SECTION 36.110 4 OF PURA? 5 A. No. No such expenses were incurred during the test year. 6 7 IV. PUC SUBSTANTIVE RULE 25.231(B) 8 Q. ARE ADVERTISING EXPENSES INCLUDED IN THE COST OF 9 SERVICE PROPOSED BY THE COMPANY IN THIS FILING? 10 A. Yes. They are included as allowed by P.U.C. SUBST. R. 25.231(b)(1)(E). 11 However, advertising to promote the increased consumption of electricity 12 and advertising to promote the industry are excluded from cost of service 13 as required by P.U.C. SUBST. R. 25.231(b)(2). 14 15 Q. WHAT WERE THE COMPANY'S ADVERTISING COSTS DURING THE 16 TEST YEAR? 17 A. The advertising costs for the test year included in the cost of service total 18 $1,194,000 which is approximately .08% of gross revenues. These costs 19 are detailed in Schedule G-4.1. 2011 ETI Rate Case 3-292 Entergy Texas, Inc. Page 10 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. DOES THIS FILING INCLUDE CONTRIBUTIONS OR DONATIONS IN 2 THE COST OF SERVICE? 3 A. No. Schedule G-4.2 shows the details of the contributions and donations 4 that have been excluded from the cost of service, including contributions 5 and donations from the Company's affiliates. 6 7 Q. PLEASE DESCRIBE THE DUES AND MEMBERSHIPS THAT ARE 8 INCLUDED IN ETI’S COST OF SERVICE. 9 A. Industry and professional association dues are included in the filing only to 10 the extent they comply with the Commission's Substantive Rules. The 11 total advertising, dues, and memberships expense included in the cost of 12 service is less than .1% of gross revenues, which is within the allowable 13 range under P.U.C. SUBST. R. 25.231(b)(1)(E). 14 15 Q. EARLIER YOU STATED ETI HAS EXCLUDED LEGISLATIVE 16 ADVOCACY EXPENSES INCLUDED IN EEI DUES. WHAT IS THE 17 BASIS FOR THE EEI EXCLUSION? 18 A. The Company's EEI dues have been reduced to exclude the portion of EEI 19 expenditures classified and reported as lobbying expense in accordance 20 with the expenditure categories agreed to by EEI and the National 21 Association of Regulatory Utility Commissioners, and as expanded by the 22 PUC staff in recent dockets before the Commission. The exclusion is 23 based on EEI’s 2011 estimate of such expenditures. 2011 ETI Rate Case 3-293 Entergy Texas, Inc. Page 11 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 V. COST OF SERVICE 2 A. Schedule A – Overall Cost of Service 3 Q. BRIEFLY DESCRIBE RFP SCHEDULE A. 4 A. Schedule A summarizes ETI's cost of service with adjustments to the test 5 year. Schedule A includes all of the adjustments requested by the 6 Company in Schedule A-3. 7 8 Q. ARE THE EXPENSES REFLECTED ON SCHEDULE A AND INCLUDED 9 IN THE COMPANY'S COST OF SERVICE REASONABLE AND 10 NECESSARY? 11 A. Yes. The testimony filed in this docket demonstrates that the expenses 12 included in this RFP constitute expenses for items that are reasonable and 13 necessary for the Company to provide service to the public and fulfill its 14 utility obligations. 15 16 Q. WHAT CONTROLS ARE IN PLACE TO ENSURE THAT ONLY THOSE 17 EXPENDITURES THAT ARE REASONABLE AND NECESSARY ARE 18 INCLUDED IN ETI’S COST OF SERVICE? 19 A. The Company and ESI maintain a system of internal accounting controls 20 that require review and authorization to determine the propriety of 21 expenditures. This review and authorization is performed by individuals 22 having managerial responsibility in their respective areas of expertise. 23 Responsible personnel are accountable for expenditures within their 2011 ETI Rate Case 3-294 Entergy Texas, Inc. Page 12 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 regions, divisions or departments and sufficient cross checks are in place 2 to assure that the procedures operate effectively. The system of internal 3 accounting controls is designed to provide reasonable assurance that 4 transactions are executed in accordance with management's authorization 5 and that assets are properly safeguarded and accounted for. Various 6 Company witnesses have filed testimony that reflects the necessity and 7 reasonableness of expenditures included in the cost of service. 8 Additionally, Deloitte & Touche performed the required test year review to 9 provide reasonable assurance that the Company prepared this filing in 10 compliance with the rules and procedures established by the Commission. 11 12 Q. PLEASE DESCRIBE SCHEDULE A-1. 13 A. Schedule A-1, sponsored by Company witness Heather G. LeBlanc, sets 14 forth the Company's overall cost of service. 15 16 Q. PLEASE DESCRIBE SCHEDULE A-2. 17 A. This schedule shows the detail of cost of service in the form prescribed by 18 the PUC's RFP instructions. Column (1) of Schedule A-2 provides the 19 description of amounts included in cost of service, rate base, revenue 20 information, and various ratios. Column (2) reflects the actual test year 21 activity, balance, or factor, for the particular item in Column (1). Column 22 (3) represents the adjustments to the per book amounts in Column (2). 2011 ETI Rate Case 3-295 Entergy Texas, Inc. Page 13 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Column (4) reflects the same information on an as-requested basis. This 2 schedule is sponsored by Company witness LeBlanc. 3 4 Q. PLEASE DESCRIBE SCHEDULE A-3. 5 A. Schedule A-3 provides a brief description and all necessary calculations to 6 support each adjustment appearing on Schedule A. 7 8 1. Adjustments 9 Q. PLEASE GENERALLY DESCRIBE THE ADJUSTMENTS INCLUDED IN 10 SCHEDULE A-3. 11 A. Generally, the adjustments bring expenses and revenues to a year-end 12 level or include in or exclude from cost of service expenses or revenues 13 that are not reflected in the Company's operations as of the close of the 14 test year, but which are known and measurable at the time of filing, and 15 which will occur either before or during the time that any modified rates will 16 be ordered into effect, expected to be in June 2012. The 12-month period 17 following the effective date when rates are first expected to be ordered 18 into effect is referred to as the "Rate Year." In this filing, the Rate Year is 19 June 1, 2012 through May 31, 2013. The resulting adjusted expenses and 20 revenues are those that, if used as the basis for setting rates for the 21 prospective period following the ordering of rates in effect, will give ETI a 22 reasonable opportunity to recover its reasonable and necessary expenses 2011 ETI Rate Case 3-296 Entergy Texas, Inc. Page 14 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 and earn a reasonable return on investment, as is required by PURA 2 Section 36.051. 3 4 Q. YOU STATED THAT ADJUSTMENTS WERE MADE FOR KNOWN AND 5 MEASURABLE CHANGES. ON WHAT AUTHORITY DO YOU RELY TO 6 DETERMINE WHAT IS KNOWN AND MEASURABLE? 7 A. P.U.C. SUBST. R. 25.231(a) and (b) state: 8 (a) Components of cost of service. Except as 9 provided for in subsection (c)(2) of this section, 10 relating to Invested capital; rate base, and 11 §23.23(b) [sic] of this title, (relating to Rate Design), 12 rates are to be based upon an electric utility's cost 13 of rendering service to the public during a historical 14 test year, adjusted for known and measurable 15 changes. The two components of cost of service 16 are allowable expenses and return on invested 17 capital. 18 (b) Allowable expenses. Only those expenses which 19 are reasonable and necessary to provide service to 20 the public shall be included in allowable expenses. 21 In computing an electric utility’s allowable 22 expenses, only the electric utility’s historical test 23 year expenses as adjusted for known and 24 measurable changes will be considered, except as 25 provided for in any section of these rules dealing 26 with fuel expenses. 27 The adjustments included in Schedules A-3 and B-1 meet the above 28 criteria for known and measurable changes to historical test year data. 2011 ETI Rate Case 3-297 Entergy Texas, Inc. Page 15 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. WHO IS SPONSORING THE ADJUSTMENTS INCLUDED IN 2 SCHEDULE A-3? 3 A. I will be sponsoring the adjustments discussed below, except where 4 otherwise noted. 5 6 a) Local Franchise Tax Adjustment (Adjustment 7) 7 Q. PLEASE DESCRIBE THE LOCAL FRANCHISE TAX ADJUSTMENT. 8 A. This adjustment removes the incremental local franchise tax and street 9 rental tax from taxes other than income tax expense. These taxes are 10 recovered in a separate rate rider. 11 12 b) Property Insurance Reserve (Adjustment 8) 13 Q. PLEASE EXPLAIN THE ADJUSTMENT TO THE PROPERTY 14 INSURANCE RESERVE ACCRUAL. 15 A. This adjustment reflects an annual property insurance accrual of 16 $8,760,000 as supported by the direct testimony of Company witness 17 Gregory S. Wilson. This reserve is part of the Company's self-insurance 18 plan. 2011 ETI Rate Case 3-298 Entergy Texas, Inc. Page 16 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 c) Margins Tax (Adjustment 9) 2 Q. PLEASE DESCRIBE THE STATE FRANCHISE TAX EXPENSE 3 ADJUSTMENT. 4 A. The Company increased taxes other than income tax expense to reflect 5 the margins tax calculation of state franchise taxes. 6 7 d) Income Taxes (Adjustment 10) 8 Q. PLEASE DESCRIBE THE INCOME TAX ADJUSTMENT. 9 A. The income tax adjustment removes prior year amounts from the test 10 year, adjusts some items to the correct test year levels, and eliminates 11 adjustments to taxable income and deferred income taxes for items which 12 are normalized in other adjustments. The current and deferred income tax 13 effects of net operating losses are also eliminated along with the deferred 14 income taxes related to the Statement of Financial Accounting Standards 15 (“SFAS”) No. 109, Accounting for Income Taxes. 16 Q. WHY ARE PRIOR YEAR AMOUNTS RECORDED IN THE TEST YEAR? 17 A. The tax return for 2009 was not completed and filed until September 2010. 18 Differences between amounts recorded on the books for current and 19 deferred income taxes and the amounts ultimately used in the filed tax 20 return were recorded on the books in the month of November 2010. Since 21 these amounts do not relate to the expenses incurred during the test year, 22 they must be eliminated from the test year. 2011 ETI Rate Case 3-299 Entergy Texas, Inc. Page 17 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. WHY DID YOU MAKE THE ADJUSTMENTS TO THE TEST YEAR 2 LEVELS OF CURRENT AND DEFERRED INCOME TAXES? 3 A. Corrections were recorded during the test year to current and deferred 4 income tax amounts that were originally recorded in periods prior to the 5 test year. These adjustments were either eliminated or the test year 6 amount was adjusted to an amount consistent with test year operating 7 expenses. 8 9 Q. PLEASE EXPLAIN THE ADJUSTMENT TO TAXABLE INCOME AND 10 DEFERRED INCOME TAXES FOR ITEMS THAT ARE NORMALIZED IN 11 OTHER ADJUSTMENTS. 12 A. Current and deferred income taxes related to items that are eliminated in 13 their entirety, or where the test year amount is substantially changed in 14 other adjustments, are eliminated or adjusted in the income tax 15 adjustment. This is to insure that the correct ending current and deferred 16 income tax effects match and correspond to the items of revenue and 17 expense in the cost of service. 18 19 Q. WHY HAVE YOU ELIMINATED DEFERRED INCOME TAXES RELATED 20 TO SFAS NO. 109? 21 A. The regulated effect of SFAS No. 109 results in recording accumulated 22 deferred income taxes that subsequently will be collected from or paid to 23 customers and are offset by corresponding regulatory assets and 2011 ETI Rate Case 3-300 Entergy Texas, Inc. Page 18 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 liabilities. SFAS No. 109 should have no effect on net operating income or 2 rate base from a regulatory standpoint and this adjustment accomplishes 3 the required net operating income neutral effect. 4 5 e) Rate Case Expense (Adjustment 11) 6 Q PLEASE DESCRIBE THE ADJUSTMENT FOR RATE CASE EXPENSES. 7 A. Based on the rate case expense estimate from ETI’s last base rate case 8 (Docket No. 37744) and adjusted for known changes to legal and 9 consulting expenses expected to be incurred during the current 10 proceeding, the Company has estimated the rate case expenses related 11 to this filing to be $12,350,000. The estimated rate case expenses will be 12 replaced by actual costs incurred as the proceeding progresses. The 13 Company requests that these amounts be recovered over three years. 14 The Company is also requesting that the average balance of rate case 15 expense be included in rate base. 16 17 f) Trade Association Dues/Legislative Advocacy (Adjustment 12) 18 Q. PLEASE EXPLAIN THIS ADJUSTMENT. 19 A. Earlier, I stated that I removed the Company’s EEI dues related to 20 lobbying from cost of service. This adjustment presents that disallowance. 21 Specifically, I eliminated 21.28% of the Company's EEI dues from the cost 22 of service. This percentage of EEI dues related to lobbying is calculated 2011 ETI Rate Case 3-301 Entergy Texas, Inc. Page 19 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 based on EEI’s 2011 estimate of such expenditures. The amount of EEI 2 dues requested is $162,916. 3 4 g) Depreciation Expense (Adjustment 13) 5 Q. PLEASE DESCRIBE THE DEPRECIATION EXPENSE ADJUSTMENT. 6 A. This adjustment shows the increase in depreciation expense resulting 7 from the application of depreciation rates approved in Docket No. 16705 8 and Docket No. 34800 to the test year end depreciable plant in service 9 balances. Test year actual depreciation expense is subtracted from this 10 pro forma amount to arrive at the adjustment of $2,459,367. Deferred 11 income taxes are also adjusted to reflect the impact of the approved 12 depreciation rates. Adjustments to affiliate depreciation expense are 13 included in Schedule G-6.2 and Adjustment 21. 14 15 h) Depreciation Study Adjustment (Adjustment 14) 16 Q. HAS THE COMPANY SUBMITTED A NEW DEPRECIATION STUDY AS 17 PART OF THIS CASE? 18 A. Yes. A depreciation study was prepared by Company witness Dane 19 Watson and the results of that study are described in Mr. Watson’s 20 testimony. Mr. Watson co-sponsors this adjustment which applies the 21 depreciation study rates to test year end plant balances. The result of this 22 adjustment is an increase in depreciation expense of $19,970,000. 2011 ETI Rate Case 3-302 Entergy Texas, Inc. Page 20 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Deferred income tax expense is also adjusted for the effect of the 2 proposed depreciation rate as are Service Schedule MSS-4 revenues. 3 4 Q. WHY ARE MSS-4 REVENUES ADJUSTED? 5 A. The new depreciation rates for production plants will be reflected in the 6 Service Schedule MSS-4 billings, resulting in decreased Service Schedule 7 MSS-4 revenues. 8 9 i) Hurricane Securitization (Adjustment 15) 10 Q. PLEASE DESCRIBE THIS ADJUSTMENT FOR HURRICANE COST. 11 A. All Hurricane Ike and Gustav costs that have been securitized are 12 removed from rate base as a result of including the contra-plant accounts 13 related to those storms. In addition, the net amount of unrecovered 14 Hurricane Rita insurance proceeds, the Hurricane Ike and Gustav 15 insurance proceeds in excess of insurance proceeds included in the 16 securitization, the carrying costs associated with Entergy Gulf States 17 Louisiana’s share of hurricane production costs (mainly associated with 18 ETI’s Sabine generating plant), the non-capital costs and the carrying 19 costs associated with ETI’s share of EGSL’s hurricane production nuclear 20 costs are included in rate base and amortized over five years in this 21 adjustment. 2011 ETI Rate Case 3-303 Entergy Texas, Inc. Page 21 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 j) Miscellaneous Adjustments (Adjustment 16) 2 Q. PLEASE DESCRIBE THE MISCELLANEOUS ADJUSTMENTS. 3 A. This pro forma includes the following adjustments: 4 1) An adjustment was made to both expense and rate base to remove 5 the impact in the cost of service of the asset retirement obligation 6 and related accretion expense recorded as result of implementing 7 SFAS No. 143. SFAS No. 143 should have no effect on net 8 operating income or rate base from a regulatory standpoint. 9 2) This adjustment eliminates from plant a reclassification recorded on 10 the Company’s books for cash flow statement purposes. This 11 adjustment has no impact on net plant. 12 3) Regulatory debits and credits that are not properly included in the 13 cost of service are eliminated in this adjustment. 14 4) Provisions for rate refunds are eliminated in this adjustment. These 15 amounts should have no impact on this case. 16 5) This adjustment removes certain expenses from the cost of service 17 that are not allowed under P.U.C. SUBST. R. 25.231(b)(2). 18 6) An adjustment was made to eliminate the SFAS No. 158 regulatory 19 asset offset to the unfunded pension liability balance. 20 7) An adjustment was made to separate facilities revenue by function. 21 8) This adjustment eliminates the test year direct costs for the 2009 22 (Docket No. 37744) rate case. 23 9) This adjustment eliminates energy efficiency costs which are 24 recovered in a rider. 25 10) This adjustment adds to rate base plant held for future use that is in 26 service or expected to be in service in the next ten years. 27 11) This adjustment eliminates prepaid balances which are not 28 recoverable in base rates. 29 12) This adjustment removes $652,627 of MISO transition expenses, 30 incurred since January 1, 2011, being considered in Docket No. 31 39741. This adjustment also includes a five year amortization of 32 $263,908 for the MISO transition expenses incurred during the test 2011 ETI Rate Case 3-304 Entergy Texas, Inc. Page 22 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 year for the time period of July 2010 through December 2010 for 2 which the Company is not seeking a deferral. This adjustment also 3 includes a three year amortization of expected MISO transition 4 costs. If the Company’s proposed accounting order for MISO 5 transition costs is approved in Docket No. 39741 prior to the 6 effective date of new rates from the instant proceeding, this 7 adjustment will not be necessary. 8 13) This adjustment eliminates expenses that were not incurred during 9 the test year. 10 11 k) Interest Synchronization (Adjustment 17) 12 Q. PLEASE DESCRIBE THE INTEREST SYNCHRONIZATION 13 ADJUSTMENT. 14 A. Per book interest expense in the tax calculation is replaced with the 15 interest expense calculated by multiplying the weighted cost of debt in the 16 requested cost of capital by adjusted rate base. 17 18 l) Customer Deposits and ESI Interest Expense (Adjustment 18) 19 Q. PLEASE DESCRIBE THE ADJUSTMENT FOR INTEREST ON 20 CUSTOMER DEPOSITS. 21 A. This adjustment is made to increase test year cost of service to reflect an 22 annualized amount for interest on active customer deposits. This 23 adjustment is made using a rate of 0.19%, the rate currently in effect 24 under the P.U.C. SUBST. R. 25.24(g). This rate was applied to the amount 25 of active customer deposits at the end of the test year. The total amount 26 of deposits is reflected as a reduction from rate base as required by 2011 ETI Rate Case 3-305 Entergy Texas, Inc. Page 23 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 P.U.C. SUBST. R. 25.231(c)(2)(C)(v). The amount of customers’ deposits 2 is $36,307,938, which results in interest expense of $68,985. 3 4 Q. DESCRIBE THE ADJUSTMENT FOR ESI AND EOI INTEREST. 5 A. The adjustment reclassifies ESI interest expense recorded below the line 6 in the test year to Account 923. The Company is not requesting a return 7 on assets owned by ESI, but is requesting recovery of actual interest costs 8 paid to ESI. 9 10 m) SFAS 106 (Adjustment 19) 11 Q. PLEASE DESCRIBE THE SFAS 106 ADJUSTMENT. 12 A. In December 1990, the Financial Accounting Standards Board (“FASB”) 13 issued SFAS 106, which was effective for fiscal years beginning after 14 December 15, 1992. Under SFAS 106, a business must account for 15 benefits other than pensions to be provided to retirees during retirement 16 on an accrual basis during the periods that the employees render service. 17 The Commission approved recovery of these costs by ETI on an 18 accrual basis in Docket No. 16705. Adjustment 19 reflects the estimated 19 2012 SFAS 106 accrual in the cost of service. 2011 ETI Rate Case 3-306 Entergy Texas, Inc. Page 24 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 n) Pension Expense (Adjustment 20) 2 Q. PLEASE EXPLAIN THE PENSION EXPENSE ADJUSTMENT. 3 A. The estimated amount of pension expense for 2012 is included in the cost 4 of service. This amount on an electric operation and maintenance 5 (“O&M”) expense was $3,871,000 compared to the per books amount of 6 $2,035,000.) The adjustment is an increase of $1,836,000 to the overall 7 pension expense included in cost of service. 8 9 o) Payroll Expense (Adjustment 22) 10 Q. PLEASE EXPLAIN THE PAYROLL EXPENSE ADJUSTMENT. 11 A. Payroll expense has been adjusted to reflect the decrease in the number 12 of ETI employees during the test year. The effective number of 13 employees who left during the test year is calculated and an average 14 salary for employees who left the Company during the test year is used to 15 calculate a total Company adjustment to decrease payroll expense. This 16 has the effect of annualizing the payroll impact of the employees who left 17 during the test year. This amount is then factored down to an electric 18 O&M amount, to which payroll taxes and benefits are added, resulting in a 19 total expense reduction of $957,695. This reduction is offset by payroll 20 increases for non-bargaining employees, effective April 1, 2011 and April 21 1, 2012, and increases for bargaining employees, which were effective 22 March 20, 2011 and August 6, 2011. The increase in expense (including 2011 ETI Rate Case 3-307 Entergy Texas, Inc. Page 25 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 benefits and payroll taxes) is $1,105,871 for a net increase to expense of 2 $148,176. 3 4 Q. WAS A SIMILAR ADJUSTMENT MADE FOR ESI EMPLOYEES? 5 A. Yes. The number of employees and wage increases were considered in a 6 similar fashion for ESI employees. The net ESI adjustment was an 7 increase in payroll expense of $852,493. 8 9 p) Service Schedule MSS-2 Adjustment (Adjustment 23) 10 Q. PLEASE DESCRIBE THE SERVICE SCHEDULE MSS-2 ADJUSTMENT. 11 A. This adjustment adjusts the Service Schedule MSS-2 test year level of 12 revenue and expense to the estimated rate year level of Service Schedule 13 MSS-2 expense. 14 15 q) Capacity Adjustment (Adjustment 24) 16 Q. PLEASE DESCRIBE ADJUSTMENT 24. 17 A. This adjustment removes purchase power capacity expenses that the 18 Company proposes to be recovered via the purchase power rider on a 19 prospective basis. The amounts removed include third-party capacity 20 purchases, Service Schedule MSS-4 purchases and Service Schedule 21 MSS-1 reserve equalization expenses. If the Commission decides these 22 capacity costs should remain in base rates, then these expenses would 2011 ETI Rate Case 3-308 Entergy Texas, Inc. Page 26 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 have to be added to the cost of service. Company witness Phillip R. May 2 discusses this in his direct testimony. 3 4 r) Property Tax (Adjustment 25) 5 Q. PLEASE DESCRIBE ADJUSTMENT 25. 6 A. This adjustment reflects property tax expenses at the level of expense that 7 will be incurred during the rate year. This adjustment is further described 8 in the direct testimony of Company witness Patricia A. Galbraith. 9 10 2. Trial Balances, Schedule A-4 11 Q. PLEASE DESCRIBE SCHEDULE A-4. 12 A. Schedule A-4 provides a detailed test year-end trial balance by major 13 FERC account. The amounts shown on this trial balance are referenced 14 to, or reconciled with, test year-end numbers appearing on Schedule A-2. 15 Column (1) lists the FERC Account Number for all amounts included on 16 Schedule A-2. Column (2) describes the account. Column (3) presents 17 the amount shown for each account in the detailed trial balance. Column 18 (4) presents the Schedule A-2 line number reference. Column (5) shows 19 the reconciliation reference. 2011 ETI Rate Case 3-309 Entergy Texas, Inc. Page 27 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 B. Schedule B - Rate Base and Return 2 Q. PLEASE DESCRIBE SCHEDULE B-1. 3 A. Schedule B-1 summarizes ETI's total Company net original cost rate base, 4 the requested adjustments to rate base, and the requested rate of return. 5 Column (1) of Schedule B-1 describes the components of rate base. 6 Column (2) reflects the total Company per book amounts for each 7 component of rate base. Column (3) shows the adjustments to total 8 Company amounts necessary to develop the per book total electric 9 amounts in column (4). Column (5) shows the necessary adjustments to 10 total electric per book amounts for each component of rate base. Column 11 (6) is the total requested rate base by component and the requested rate 12 of return. Schedule B-1 is co-sponsored by Company witness LeBlanc. 13 14 1. Rate Base Adjustments 15 a) Cash Working Capital (Adjustment 6) 16 Q. PLEASE DESCRIBE HOW THE CASH WORKING CAPITAL 17 ALLOWANCE IS CALCULATED. 18 A. Schedule E-4 contains the calculation of the cash working capital 19 allowance for operating and maintenance expenses obtained from the 20 lead-lag study. P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV) and (V) require 21 that a lead-lag study be performed to determine the reasonableness of a 22 cash working capital allowance. A lead-lag study is a detailed analysis of 23 the Company's normal day-to-day business activities performed to assist 2011 ETI Rate Case 3-310 Entergy Texas, Inc. Page 28 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 in determining the amount of investment that is necessary to fund these 2 activities before the Company is reimbursed by its customers. Company 3 witness Jay Joyce discusses the lead-lag study in his direct testimony. 4 5 b) Income Tax (Adjustment 10) 6 Q. PLEASE DESCRIBE THE RATE BASE EFFECTS OF THE INCOME TAX 7 ADJUSTMENT. 8 A. As described earlier in my testimony, all ADIT effects of SFAS 109 are 9 eliminated from the test year. ADIT associated with items removed from 10 the case are eliminated in the adjustment. 11 12 2. Schedules B-1.1 through B-2.1 13 Q. PLEASE DESCRIBE SCHEDULE B-1.1. 14 A. Schedule B-1.1 reflects the Company’s allocation of rate base to the 15 Texas Retail jurisdiction, which is presented in the same format as 16 Schedule B-1. Company witness LeBlanc sponsors this schedule. 17 18 Q. PLEASE DESCRIBE SCHEDULE B-1.2. 19 A. This schedule is not applicable to the Company because the Company's 20 requested plant in service is not less than 100% of original prudent cost. 21 Q. PLEASE DESCRIBE SCHEDULE B-1.3. 22 A. Schedule B-1.3 reports that there are no penalties or fines included in the 23 Company's requested plant in service on Schedule B-1. 2011 ETI Rate Case 3-311 Entergy Texas, Inc. Page 29 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE EXPLAIN SCHEDULE B-1.4. 2 A. There were no post test year adjustments to rate base. 3 4 Q. PLEASE DESCRIBE SCHEDULE B-2. 5 A. Schedule B-2 reports the monthly balance of each accumulated provision 6 account, the amount accrued each month, and the amount charged off 7 each month during the test year. The same information is provided in total 8 for each of the calendar years 2007 through 2010. 9 10 Q. PLEASE DESCRIBE SCHEDULE B-2.1. 11 A. Schedule B-2.1 provides an explanation of the Company's policy 12 regarding accumulated provision accounts and the benefits these 13 accounts provide to customers. 14 15 C. Schedule C – Original Cost of Plant 16 Q. PLEASE DESCRIBE SCHEDULE C-1. 17 A. This schedule summarizes the original cost of utility plant as of the 18 beginning of the test year, shows additions, retirements and transfers, and 19 the balances at the end of the test year. Adjustments made to the book 20 balances for requested plant amounts are also included in this schedule. 2011 ETI Rate Case 3-312 Entergy Texas, Inc. Page 30 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE C-2. 2 A. This schedule presents the data shown in Schedule C-1, detailed by each 3 of the major plant accounts. 4 5 Q. PLEASE DESCRIBE SCHEDULE C-3. 6 A. Schedule C-3 is a monthly presentation of plant balances by primary or 7 functional classification by primary plant account as well as any requested 8 adjustments to the balances. 9 10 Q. PLEASE DESCRIBE SCHEDULE C-4.1. 11 A. This schedule lists items of $100,000 or more by functional group included 12 in Construction Work in Progress (“CWIP”) with details concerning the 13 items. 14 15 Q. PLEASE DESCRIBE SCHEDULE C-4.2, CWIP ALLOWED IN RATE 16 BASE. 17 A. The schedule shows that no CWIP was requested in rate base in Docket 18 Nos. 34800 or 37744, the Company's two most recent base rate 19 proceedings. In this filing, the Company is not requesting CWIP in rate 20 base. 2011 ETI Rate Case 3-313 Entergy Texas, Inc. Page 31 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE C-5, ALLOWANCE FOR FUNDS USED 2 DURING CONSTRUCTION (“AFUDC”) AND CONSTRUCTION 3 OVERHEADS. 4 A. This schedule details the methods, procedures, and calculations in 5 capitalizing AFUDC. Also shown are the capitalization rates for each of 6 the five years ended December 31, 2006 through 2010 along with the test 7 year, and the amounts of AFUDC generated and transferred to plant in 8 service. 9 10 Q. PLEASE DISCUSS SCHEDULES C-6 THROUGH C-10. 11 A. Theses schedules are not applicable to ETI, which has no nuclear fuel. 12 13 D. Schedule D – Accumulated Depreciation 14 Q. PLEASE DESCRIBE SCHEDULE D. 15 A. Schedule D is a narrative description of computer programs, diskettes, 16 schedules, and file names associated with Schedules D-1, D-3, D-4, D-6, 17 D-7, and D-8. 18 19 Q. PLEASE DESCRIBE SCHEDULE D-1. 20 A. Schedule D-1 shows the reserve for depreciation and amortization at the 21 beginning of the test year, provisions, salvage, cost of properties retired, 22 cost of removal, other additions and/or reductions, and the reserve for 2011 ETI Rate Case 3-314 Entergy Texas, Inc. Page 32 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 depreciation and amortization at the end of the test year. Adjustments 2 and the as-adjusted amounts are also shown. 3 4 Q. PLEASE DESCRIBE SCHEDULE D-2. 5 A. Schedule D-2 is a narrative description of the methods and procedures 6 followed in booking depreciation and plant retirements and abandonments. 7 8 Q. PLEASE DESCRIBE SCHEDULE D-3. 9 A. Schedule D-3 details plant held for future use (“PHFU”). 10 11 Q. PLEASE DESCRIBE SCHEDULE D-4. 12 A. This schedule shows depreciable plant, the depreciation rate for the test 13 year, and test year depreciation. The requested depreciable plant and 14 existing depreciation rates are shown, requested depreciation expense is 15 computed, and the adjustment to depreciation expense requested is 16 presented in the last column. 17 18 Q. PLEASE DESCRIBE SCHEDULE D-5. 19 A. The depreciation study prepared by Company witness Watson is 20 referenced in Schedule D-5. 2011 ETI Rate Case 3-315 Entergy Texas, Inc. Page 33 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE D-6. 2 A. This schedule provides projected retirement dates for the Company’s 3 generating units. Company witness Robert R. Cooper co-sponsors this 4 schedule with me. 5 6 Q. PLEASE DESCRIBE SCHEDULE D-7. 7 A. This schedule provides summary data for cost of removal, salvage, and 8 net salvage, and is provided by functional classification. 9 10 Q. PLEASE DESCRIBE SCHEDULE D-8. 11 A. This schedule provides the average service life of each group of assets 12 and the Iowa Curves used to determine the lives. 13 14 E. Schedule E – Short-Term Assets and Inventories 15 Q. PLEASE DESCRIBE SCHEDULE E-1. 16 A. Schedule E-1 lists each short-term asset requested in rate base (e.g., 17 materials and supplies, prepayments, and fuel inventory). The schedule 18 includes book balances for the month end before the test year begins and 19 each of the twelve months of the test year in order to arrive at a 13 month 20 average. 2011 ETI Rate Case 3-316 Entergy Texas, Inc. Page 34 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE E-1.1. 2 A. Schedule E-1.1 details the monthly per book balances by category 3 included in Schedule E-1. 4 5 Q. PLEASE DESCRIBE SCHEDULE E-1.2. 6 A. Schedule E-1.2 explains the Company’s policies related to obsolete, 7 damaged, or no-longer-used inventory. 8 9 Q. PLEASE DESCRIBE SCHEDULE E-1.3. 10 A. Schedule E-1.3 indicates there have been no changes in accounting policy 11 for the book balances (started capitalizing, quit keeping item on hand, 12 change in write-off procedures, etc.) for items included in Schedule E-1. 13 14 Q. PLEASE DESCRIBE SCHEDULE E-2.2 15 A. Schedule E-2.2 details the optimal coal inventory level for the Company. 16 17 Q. PLEASE DESCRIBE SCHEDULE E-2.3. 18 A. Schedule E-2.3 presents a detailed analysis of fossil fuel inventories on 19 hand at the end of the test year. 2011 ETI Rate Case 3-317 Entergy Texas, Inc. Page 35 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE E-2.4. 2 A. Schedule E-2.4 presents ETI's monthly fossil fuel inventory levels for the 3 test year ended June 30, 2011. 4 5 Q. PLEASE DESCRIBE SCHEDULE E-4. 6 A. Schedule E-4 details the application of the lead-lag study to calculate the 7 rate base effect of the lead lag study. This schedule is co-sponsored by 8 Company witness Joyce. 9 10 Q. PLEASE DESCRIBE SCHEDULES E-5 AND E-6. 11 A. Schedule E-5 presents the amount of prepayment and materials and 12 supplies charged to O&M expense by month during the test year. 13 Schedule E-6 contains information about customer deposits at the end of 14 the test year. 15 16 F. Schedule G – Accounting Information 17 1. Payroll Schedules 18 Q. PLEASE DESCRIBE SCHEDULE G-1. 19 A. Schedule G-1 provides a narrative of the payroll practices of the 20 Company. Schedules G-1.6 and G-2.1 described below are co-sponsored 21 by Company witness Kevin G. Gardner. 2011 ETI Rate Case 3-318 Entergy Texas, Inc. Page 36 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE G-1.1. 2 A. Schedule G-1.1 provides annual gross payroll information for each year of 3 the three-year period ending December 31, 2010, as well as for each 4 month of the test year. The information is categorized by regular payroll, 5 overtime payroll, other, and total payroll. 6 7 Q. PLEASE DESCRIBE SCHEDULE G-1.2. 8 A. Schedule G-1.2 provides annual gross regular payroll information for each 9 year of the three-year period ending December 31, 2010, as well as for 10 each month of the test year. The information is categorized by union 11 payroll, non-union payroll, and total payroll. 12 13 Q. PLEASE DESCRIBE SCHEDULE G-1.3. 14 A. Schedule G-1.3 provides annual gross payroll information for each year of 15 the three-year period ending December 31, 2010, as well as for each 16 month of the test year. The information is categorized by payroll 17 expensed, payroll capitalized, other payroll, and total payroll. 18 19 Q. PLEASE DESCRIBE SCHEDULE G-1.4. 20 A. Schedule G-1.4 provides the amount of payroll charged to joint owners of 21 certain power plants operated by ETI for each year of the three-year 22 period ending December 31, 2010, as well as for each month of the test 23 year. This schedule presents information for units in which there are joint 2011 ETI Rate Case 3-319 Entergy Texas, Inc. Page 37 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 owners, ETI is the operator, and the joint owner reimburses ETI for the 2 payroll as part of the billing for O&M costs. 3 4 Q. PLEASE DESCRIBE SCHEDULE G-1.6. 5 A. Schedule G-1.6 reports all payments other than standard pay or overtime 6 pay made to ETI employees for each year of the three-year period ended 7 December 31, 2010, as well as for each month of the test year. 8 9 2. Pensions and Benefits Schedules 10 Q. PLEASE DESCRIBE SCHEDULE G-2.1. 11 A. A summary of ETI's pension fund activity is included in Schedule G-2.1. 12 The schedule includes pension expense pursuant to SFAS No. 87, actual 13 pension payments to the fund, actuarial minimums and actuarial 14 maximum, along with supporting documentation. 15 16 Q. PLEASE DESCRIBE SCHEDULE G-2.2. 17 A. Schedule G-2.2 provides details concerning SFAS 106 expense incurred 18 during the test year and as requested in cost of service. 2011 ETI Rate Case 3-320 Entergy Texas, Inc. Page 38 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 3. Bad Debt Expense Schedule 2 Q. PLEASE DESCRIBE SCHEDULE G-3. 3 A. Schedule G-3 contains information concerning bad debt expense including 4 the methodology of calculating monthly expense and the amount of write- 5 offs. 6 7 4. Advertising, Contributions, and Dues Schedules 8 Q. PLEASE DESCRIBE SCHEDULE G-4. 9 A. This schedule presents a summary of advertising, contributions, and 10 donations, and organization memberships and dues expenses subject to 11 the 0.3% of revenue limitation. The schedule includes the FERC account 12 charged, category, schedule number that details the expense, and test 13 year expense. 14 15 Q. PLEASE DESCRIBE SCHEDULES G-4.1 THROUGH G-4.1c. 16 A. Schedule G-4.1 provides a summary of advertising expense categorized 17 by: FERC account, category schedule number, and test year amount. 18 Schedules G-4.1a through G-4.1c provide a summary of expense for 19 informational/instructional advertising, promoting and retaining usage, and 20 general advertising expense, respectively. 21 22 Q. PLEASE DESCRIBE SCHEDULE G-4.1d. 23 A. Schedule G-4.1d requires detail about advertising costs capitalized. 2011 ETI Rate Case 3-321 Entergy Texas, Inc. Page 39 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULES G-4.2 THROUGH G-4.2c. 2 A. Schedule G-4.2 provides a summary of contribution and donation 3 expenses in the following categories: educational; community service; and 4 economic development. The schedule includes the FERC account 5 charged, the description of the contribution, the schedule number that 6 details the expense, and the test year amount. Schedules G-4.2a through 7 G-4.2c detail educational, community service, and economic development 8 contribution and donations expense, respectively. 9 10 Q. PLEASE DESCRIBE SCHEDULES G-4.3 THROUGH G-4.3e. 11 A. Schedule G-4.3 provides a summary of membership dues or support 12 expenses categorized by: industry organizations; business/economic 13 organizations; professional organizations; social/recreational/religious 14 organizations; and political organizations. The schedule includes the 15 FERC account charged, the category, the schedule number that details 16 the expense, and the test year amount. Also included are certain amounts 17 that ETI has excluded from its requested cost of service. Schedules G- 18 4.3a through G-4.3e provide: a summary of electric industry organization 19 dues; business and economic dues; professional dues; social, 20 recreational, fraternal or religious expenses; and political organization 21 expenses, respectively. 2011 ETI Rate Case 3-322 Entergy Texas, Inc. Page 40 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 5. Exclusions from Test Period Schedules 2 Q. PLEASE DESCRIBE SCHEDULES G-5 THROUGH G-5.1b. 3 A. Schedule G-5 presents a summary of all test year expenditures in the 4 categories of: legislative advocacy expenses; penalties and fines; other 5 exclusions; social/recreational/religious; and political. The schedule 6 includes a description of the expenditure, the schedule number that details 7 the expenditure, and the test year amount. Schedules G-5.1 through G- 8 5.1b summarize legislative advocacy expense, payments made to 9 individuals registered to lobby on behalf of the utility during the test year, 10 and payments made to individuals or firms who monitored legislation for 11 the utility during the test year, respectively. The Company is not 12 requesting lobbying expenses in the cost of service in accordance with 13 PURA § 36.062. 14 15 Q. PLEASE DESCRIBE SCHEDULE G-5.2. 16 A. Schedule G-5.2 requires a summary of all penalties and fines included in 17 the test year expense. ETI is not, however, requesting recovery of any 18 fines or penalties in its cost of service. 19 20 Q. PLEASE DESCRIBE SCHEDULE G-5.3. 21 A. Schedule G-5.3 presents a summary of all test year expenditures referred 22 to in P.U.C. SUBST. R. 25.231(b)(2), but not shown in Schedules G-4.3d, 23 G-4.3e, G-5.1, and G-5.2. 2011 ETI Rate Case 3-323 Entergy Texas, Inc. Page 41 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE G-5.4. 2 A. Schedule G-5.4 requires amounts which were excluded from cost of 3 service by the PUC in the Company's most recent rate case not resolved 4 by settlement, if any, in the last five years. The only rate cases applicable 5 to ETI or its predecessor EGSI resolved in the past five years were the 6 base rate case filed in Docket No. 34800 in September 2007 and Docket 7 No. 37744 in December 2009, which were resolved by settlement. This 8 schedule, therefore, does not apply to this case. 9 10 Q. PLEASE DESCRIBE SCHEDULE G-5.5. 11 A. Schedule G-5.5 requests payments made during the test year and 12 included in cost of service for activities or services similar to those 13 excluded from either of the two most recent rate cases not resolved by 14 settlement. The two most recent bundled rate cases applicable to ETI or 15 its predecessor EGSI were resolved by settlement filed in Docket No(s). 16 37744 and 34800. EGSI did file an unbundled rate case in Docket No. 17 22356 in 2000, but that proceeding did not result in a final order. This 18 schedule, therefore, does not apply to this case. 19 20 6. Income Tax Schedules 21 Q. PLEASE DESCRIBE SCHEDULE G-7.1. 22 A. Schedule G-7.1 is the reconciliation of book net income to taxable net 23 income for the test year and for the most recently filed tax return. The 2011 ETI Rate Case 3-324 Entergy Texas, Inc. Page 42 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 workpapers for Schedule G-7.1 contain explanations of all items in the 2 reconciliation along with an explanation of items that appeared in the tax 3 return that have not been considered in the test year calculation. This 4 schedule is co-sponsored by Company witness Rory L. Roberts. 5 6 Q. ARE YOU FILING SCHEDULE G-7.2, PLANT ADJUSTMENTS? 7 A. Yes. This schedule is not applicable to ETI in this rate case because ETI 8 has not purchased or constructed any new generating unit since the 9 Company’s last rate case. 10 11 Q. PLEASE EXPLAIN SCHEDULE G-7.4, ACCUMULATED DEFERRED 12 FEDERAL INCOME TAXES (“ADFIT”). 13 A. This schedule shows the balance sheet amount of ADFIT for the twelve 14 months of the test year, as well as requested adjustments to the balances. 15 The deferrals are segregated by specific items giving rise to the deferral. 16 This schedule also shows the additional deferred taxes that were recorded 17 as a result of adopting SFAS 109. SFAS 109 has no effect on rate base 18 compared to the prior standard for accounting for income taxes, 19 Accounting Principles Board No. 11. As stated earlier in my testimony, 20 recording income taxes in accordance with SFAS 109 is revenue neutral. 21 Schedules G-7.4 through G-7.4d are co-sponsored by Company witness 22 Roberts. 2011 ETI Rate Case 3-325 Entergy Texas, Inc. Page 43 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE G-7.4b, ADJUSTMENTS TO ADFIT. 2 A. Adjustments to balance sheet amounts are detailed on this schedule. The 3 reasons for these adjustments are shown and supporting calculations are 4 included. A description of the adjustments is provided in the discussion of 5 the income tax pro forma (Adjustment 10). 6 7 Q. WHAT IS THE PROPER RATE TREATMENT FOR THE DEFERRED 8 TAXES SHOWN ON SCHEDULE G-7.4, ADFIT? 9 A. The total deferred taxes from Schedule G-7.4 are an adjustment to rate 10 base on Schedule B-1. The pre-1971 ITC shown on Schedule G-7.5e is 11 also an adjustment to rate base on Schedule B-1. 12 13 Q. WHY IS THE PRE-1971 ITC A DEDUCTION TO RATE BASE WHILE 14 THE POST-1970 ITC IS NOT DEDUCTED FROM RATE BASE? 15 A. Use of the pre-1971 ITC for rate purposes was not restricted by the Tax 16 Code. An election was made by the Company to not reduce rate base by 17 the Post-1970 ITC, but to instead amortize these credits to cost of service 18 no more rapidly than ratably. This treatment is in accordance with Section 19 46(f)(2) of the Tax Code. 2011 ETI Rate Case 3-326 Entergy Texas, Inc. Page 44 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE G-7.4c, ADFIT AND ITC - PLANT 2 ADJUSTMENTS AND ALLOCATIONS. 3 A. This schedule seeks information on the balance sheet ADFIT and ITC for 4 additions to new generating plant-in-service since the Company's last filing 5 and any plant adjustments to the test year end. There have been no new 6 generating units added to rate base since the Company's last filing or 7 plant adjustments to the test year end. 8 9 Q. PLEASE DESCRIBE SCHEDULE G-7.4d, ADFIT - RATE CASE 10 EXPENSES. 11 A. This schedule is inapplicable to ETI for this rate case. The Company does 12 not have any accumulated deferred federal income tax (ADFIT) related to 13 Texas Retail rate case expenses. 14 15 Q. PLEASE DESCRIBE SCHEDULE G-7.5c, ITC UTILIZED - STAND- 16 ALONE BASIS. 17 A. This schedule shows ITC utilized as if the Company had filed on a stand- 18 alone basis consistent with the limitations included in the Tax Code based 19 on the stand-alone methodology. 2011 ETI Rate Case 3-327 Entergy Texas, Inc. Page 45 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE G-7.5e, FERC ACCOUNT 255 2 BALANCE. 3 A. This schedule shows the FERC account balance for Account 255, 4 Accumulated Deferred ITC, allocated between nuclear production plant 5 and other plant. 6 7 Q. PLEASE DESCRIBE SCHEDULE G-7.6, ANALYSIS OF TEST YEAR FIT 8 AND REQUESTED FIT - TAX METHOD 2. 9 A. Schedule G-7.6 calculates FIT for the test year and requested FIT using 10 Tax Method 2. Included with this schedule are supporting explanations 11 and calculations. This method of calculating FIT expense determines the 12 components of FIT separately. These components include the taxes 13 payable currently, the deferred taxes, and the amortization of ITC. 14 Company witness Roberts and LeBlanc co-sponsor Schedules G-7.6 and 15 G-7.6a. 16 17 Q. PLEASE DESCRIBE SCHEDULE G-7.6a, ANALYSIS OF DEFERRED 18 FIT. 19 A. This schedule is an analysis of the deferred FIT expense as shown on 20 Schedule G-7.6. Workpapers supporting the calculation(s) are included in 21 WP/G-7.6. 2011 ETI Rate Case 3-328 Entergy Texas, Inc. Page 46 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE G-7.7, ANALYSIS OF ADDITIONAL 2 DEPRECIATION REQUESTED. 3 A. This schedule requests support for any requested adjustment to return for 4 additional depreciation. ETI is not requesting an adjustment to return for 5 additional depreciation expense. 6 7 Q. PLEASE DESCRIBE SCHEDULE G-7.8, ANALYSIS OF TEST YEAR FIT 8 AND REQUESTED FIT - TAX METHOD 1. 9 A. This schedule represents what is known as the Method 1 calculation of 10 test year and requested FIT. This is sometimes described as the "return 11 method" for computing FIT. Company witness Roberts and LeBlanc co- 12 sponsor Schedule G-7.8. 13 Return is the total amount shown on Schedule B-1, line 25. 14 Regulated interest expense is defined as the weighted cost of debt 15 (Schedule K-1, Line 3, column 6) multiplied by the requested rate base 16 (Schedule B-1, line 24). Interest expense is subtracted from return to 17 arrive at the taxable amount of return before adjustments. 18 Also subtracted is the amortization of taxes in excess of the 19 statutory 35% rate and other items that, before adoption of SFAS 109, 20 were called permanent and flow-through differences. The most significant 21 of these differences is AFUDC, which for many years was recorded on a 22 net of tax basis for both the interest and equity components of AFUDC. 2011 ETI Rate Case 3-329 Entergy Texas, Inc. Page 47 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. WHAT IS THE RESULT OF THE TAX METHOD 1 CALCULATIONS? 2 A. The result of the above calculation equals the taxable component of 3 return. This taxable return is multiplied by the tax factor 0.5384615 (Tax 4 Rate divided by One minus the Tax Rate, (which is .35/1-.35)), resulting in 5 the total FIT amount before adjustments. 6 From this amount is subtracted the ITC amortization and 7 amortization of excess deferred taxes to determine total FIT (Method 1). 8 9 Q. DOES THE AMOUNT COMPUTED UNDER METHOD 1 DIFFER FROM 10 THE AMOUNT SHOWN ON SCHEDULE G-7.6, ANALYSIS OF TEST 11 YEAR FIT AND REQUESTED FIT - TAX METHOD 2, AT REQUESTED 12 RATES? 13 A. No, it is the same amount. The two calculations result in the same 14 amount of FIT expense. 15 16 Q. PLEASE DESCRIBE SCHEDULE G-7.9, AMORTIZATION OF 17 PROTECTED AND UNPROTECTED EXCESS DEFERRED TAXES. 18 A. This schedule summarizes the amortization of protected and unprotected 19 excess deferred FIT. Schedules G-7.9 through G.7-9c are sponsored by 20 Company witness Roberts. 2011 ETI Rate Case 3-330 Entergy Texas, Inc. Page 48 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE G-7.9a. 2 A. This schedule reflects the amount of protected excess deferred FIT 3 included in the test year and the unamortized balance of protected excess 4 deferred FIT as of June 30, 2011. 5 6 Q. PLEASE DESCRIBE SCHEDULE G-7.9b. 7 A. Schedule G-7.9b provides a reconciliation of excess deferred FIT as of 8 June 30, 2011. 9 10 Q. WHAT INFORMATION IS PROVIDED IN SCHEDULE G-7.9c? 11 A. The Company’s unprotected excess deferred FIT was fully amortized at 12 the end of July 1991. 13 14 Q. PLEASE DESCRIBE SCHEDULE G-7.10, EFFECTS OF ACCOUNTING 15 ORDER DEFERRALS. 16 A. This schedule lists and explains all effects on requested FIT and ADFIT of 17 the Company's deferred accounting approved by the Commission in 18 previous dockets. These are no accounting order deferrals remaining on 19 ETI’s books. 20 21 Q. PLEASE DESCRIBE SCHEDULE G-7.11, EFFECTS OF POST-TEST 22 YEAR ADJUSTMENTS. 23 A. The Company made no post-test year adjustments to rate base. 2011 ETI Rate Case 3-331 Entergy Texas, Inc. Page 49 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. SCHEDULES G-7.12 AND G-7.12a RELATE TO DEFERRED FIT THAT 2 IS PART OF A RATE MODERATION PLAN. DOES THE COMPANY 3 HAVE A RATE MODERATION PLAN? 4 A. No. 5 6 Q. PLEASE DESCRIBE SCHEDULE G-7.13, LIST OF FIT TESTIMONY. 7 A. Schedule G-7.13 simply provides page references to Company 8 witness testimony supporting FIT and ADFIT. 9 10 7. Outside Services Schedule 11 Q. PLEASE DESCRIBE SCHEDULE G-8. 12 A. This schedule presents information on all outside services employed 13 during the test year that appear in the FERC 900 series accounts. The 14 information is shown as follows: column (a) is the FERC account; column 15 (b) is the vendor sorted by category; column (c) is the purpose of the 16 service; column (d) indicates whether the service is recurring or non- 17 recurring; and column (e) is the amount. Items of a non-recurring nature 18 are removed or normalized in the requested cost of service. 2011 ETI Rate Case 3-332 Entergy Texas, Inc. Page 50 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 8. Taxes Other Than Income Tax Schedules 2 Q. PLEASE DESCRIBE SCHEDULE G-9. 3 A. This schedule shows the amount of taxes other than income taxes for the 4 three most recent calendar years, the test year expense, adjustments to 5 the test year and the total adjusted tax amount. 6 7 Q. PLEASE DESCRIBE SCHEDULE G-9.1. 8 A. Schedule G-9.1 reflects the ad valorem taxes assessed and the related 9 plant balances for the last three calendar years and the test year. 10 11 9. Factoring Expense Schedule 12 Q. PLEASE DESCRIBE SCHEDULE G-10. 13 A. This schedule is not applicable to ETI because the Company does not 14 factor accounts receivable. 15 16 10. Deferred Expense Information Schedule 17 Q. PLEASE DESCRIBE SCHEDULE G-11. 18 A. Schedule G-11 includes information concerning all amortization expense 19 either included in the test year or requested by the Company in this rate 20 filing. The information is categorized by: 21 authorizing docket; 22 original amount to be amortized; 23 deferral period; 2011 ETI Rate Case 3-333 Entergy Texas, Inc. Page 51 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 date amortization began; 2 total amortization taken as of the beginning of the test year; 3 amortization expense for the test year; 4 amortization expense included in requested cost of service; 5 and 6 unamortized amount as of the end of the test year. 7 8 11. Below the Line Expenses Schedule 9 Q. PLEASE DESCRIBE SCHEDULE G-12. 10 A. Schedule G-12 presents a complete analysis of all expenses charged 11 "below the line" during the test year. Verification that "below the line" 12 expenses have been eliminated from the filing has been provided in the 13 workpapers (WP/G-12) for this schedule. The starting point for the 14 Company’s cost of service is net utility operating income. None of the 15 items recorded below the line are included in the calculation of net utility 16 operating income and none of the items recorded below the line are 17 included in any adjustment that would include these amounts in cost of 18 service. 19 20 12. Non-Recurring Expense Schedule 21 Q. PLEASE DESCRIBE SCHEDULE G-13. 22 A. Schedule G-13 describes any nonrecurring extraordinary expenses the 23 Company is requesting in this filing. The only such item the Company is 2011 ETI Rate Case 3-334 Entergy Texas, Inc. Page 52 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 including in the filing is the recovery of insurance amounts related to storm 2 securitizations as described in Adjustment 15. 3 4 13. Rate Case Expense Schedules 5 Q. PLEASE DESCRIBE SCHEDULE G-14. 6 A. Schedule G-14 details the various expenses charged to FERC Account 7 928, Regulatory Expense, during the test year, the Company’s 8 adjustments to the test year amounts, and the Company’s request for 9 each item. 10 11 Q. PLEASE DESCRIBE SCHEDULE G-14.1. 12 A. Schedule G-14.1 provides information concerning estimated rate case 13 expenses for this case, detailed by each type of expense. 14 15 Q. PLEASE DESCRIBE SCHEDULE G-14.2. 16 A. Schedule G-14.2 provides information concerning rate case expenses 17 related to previous rate applications which were not previously considered 18 by the Commission. 19 20 14. Monthly O&M Schedules 21 Q. PLEASE DESCRIBE SCHEDULE G-15. 22 A. Schedule G-15 includes the O&M expense for the test year. The schedule 23 provides O&M expense by month, by account, and the total booked for the 2011 ETI Rate Case 3-335 Entergy Texas, Inc. Page 53 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 test year. This schedule also includes total adjusted O&M expenses 2 claimed, including subtotals by functional classification. The Company 3 has also detailed the amount of O&M expense by account that was the 4 result of a transaction with an affiliate and presents this information in the 5 Schedule G-6 series of Schedules. 6 7 G. Schedule H – Engineering Information 8 Q. PLEASE DESCRIBE SCHEDULES H-1 THROUGH H-1.2d. 9 A. Schedules H-1 through H-1.2d provide detailed information related to the 10 production plant O&M expenses for all power generating stations. 11 Schedules H-1 through H-1.2d are co-sponsored by Company witness 12 Winfred W. Garrison. 13 14 Q. PLEASE DESCRIBE SCHEDULE H-2. 15 A. Schedule H-2 provides the information in Schedule H-1 adjusted for 16 known and measurable changes. This schedule is co-sponsored by 17 Company witness Garrison. 18 19 Q. PLEASE DESCRIBE SCHEDULE H-3. 20 A. Schedule H-3 is the summary of production O&M expenses incurred for 21 the years 2006 through 2010. 2011 ETI Rate Case 3-336 Entergy Texas, Inc. Page 54 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DESCRIBE SCHEDULE H-5.1. 2 A. Schedule H-5.1 describes the criteria used to determine which unit 3 improvements, modifications, and repairs become capitalized costs. The 4 instructions for Schedule H-5.1 require that workpapers be provided for 5 the retirement units and expense item information (Retirement Catalog). 6 ETI maintains a Retirement Catalog for capitalized units, which is provided 7 in WP/H-5.1. 8 9 Q. PLEASE DESCRIBE SCHEDULE H-10. 10 A. This schedule notes that the most recent River Bend Station 11 Decommissioning Cost Study, dated November 2009, was filed with the 12 PUC on December 30, 2009 in Docket No. 37744 as Exhibit WAC-1 to the 13 testimony of Company witness William A. Cloutier. The Company is not 14 proposing any changes or adjustments to that study. 15 16 H. Schedule J – Financial Statements 17 Q. PLEASE DESCRIBE SCHEDULE J. 18 A. This schedule provides the financial statements considered necessary for 19 presentation of the Company's financial position in accordance with 20 generally accepted accounting practices. The statements provided are 21 the Income Statement, Balance Sheet, Retained Earnings, and Statement 22 of Cash Flows for both the test year and twelve months immediately 2011 ETI Rate Case 3-337 Entergy Texas, Inc. Page 55 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 preceding the test year. Also included are the footnotes to the financial 2 statements. 3 4 Q. PLEASE DESCRIBE SCHEDULE J-1. 5 A. This schedule provides a reconciliation of the balance sheet and the 6 income statement presented on a total Company basis in Schedule J to 7 the same information on a total electric basis. 8 9 Q. PLEASE DESCRIBE SCHEDULE J-2. 10 A. This schedule provides the consolidated financial statements, including 11 the footnotes, for Entergy, the parent of ETI. 12 13 I. Schedule K – Financial Information 14 Q. WOULD YOU PLEASE EXPLAIN SCHEDULE K-1. 15 A. Schedule K-1 of the RFP shows the overall rate of return on invested 16 capital of the Company. Schedules K-1 through K-6 are co-sponsored by 17 Company witness Chris E. Barrilleaux. Column (4) of Schedule K-1 shows 18 that the Company's capitalization percentages are 50.08% debt and 19 49.92% common equity. The component cost rates shown in Column (5) 20 are calculated in supporting Schedules K-2 and K-3. The required cost of 21 common equity requested by the Company in this filing is discussed in the 22 testimony of Company witness Samuel C. Hadaway. The cost of equity 23 reflected in Schedule K-1 is 10.6%. 2011 ETI Rate Case 3-338 Entergy Texas, Inc. Page 56 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 The component cost rates in Column (5) of Schedule K-1 are then 2 applied to the capitalization percentages shown in Column (4) to obtain 3 the overall weighted cost of capital of 8.6683% shown in Column (6). The 4 net original cost rate base of $1,741,096,000 on line 5 is multiplied by the 5 overall rate of return to obtain the requested dollar return on rate base of 6 $150,923,000 on line 7 of Schedule K-1. 7 The capital amount for common equity reflects the common equity 8 balance as of September 30, 2011. 9 10 Q. PLEASE DISCUSS SUPPORTING SCHEDULE K-2. 11 A. Schedule K-2 is no longer applicable to the Company as it has no 12 preferred stock. 13 14 Q. PLEASE DISCUSS SCHEDULE K-3. 15 A. The adjusted overall cost of long-term debt of 6.74% is calculated in 16 Schedule K-3 of the RFP. Details of the sinking fund requirements for 17 long-term debt are also provided in Schedule K-3. 18 19 Q. PLEASE DISCUSS SCHEDULE K-4. 20 A. This schedule shows a listing of notes outstanding at the end of the test 21 year, and at the end of each quarter for the past two years. 2011 ETI Rate Case 3-339 Entergy Texas, Inc. Page 57 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. PLEASE DISCUSS SCHEDULE K-5. 2 A. Schedule K-5 is a summary of security issuance restrictions that apply to 3 the issuance of preferred stock and long-term debt as of the end of the 4 test year, the most recent fiscal year and projections for three fiscal years. 5 The Mortgage Indenture coverage calculation and the Articles of 6 Incorporation calculation provide the restrictions on the amount of 7 securities that can be issued under each test. The projections of each 8 financial test provided for three fiscal years are sponsored by Company 9 witness Barrilleaux. 10 11 Q. PLEASE DESCRIBE SCHEDULE K-6. 12 A. Schedule K-6 contains thirteen specific ratios for the fiscal years 2006 13 through 2010 and the test year, as well as three projected fiscal years. I 14 co-sponsor the projected ratios along with Company witness Barrilleaux. 15 16 J. Schedule M – Nuclear Plant Decommissioning 17 Q. PLEASE DESCRIBE SCHEDULE M-1. 18 A. Schedule M-1 provides general information, decommissioning cost and 19 funding for each decommissioning fund the Company has established. 20 21 Q. PLEASE DESCRIBE SCHEDULE M-2. 22 A. Schedule M-2, the decommissioning funding plan established by the 23 Company provides the actual and projected annual contributions, 2011 ETI Rate Case 3-340 Entergy Texas, Inc. Page 58 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 administrative fees, earnings on the funds, tax payments, 2 decommissioning outlays and accumulated fund balances by year. 3 4 Q. WHAT IS THE COMPANY PROPOSING BASED ON THE M-2 5 INFORMATION? 6 A. The Company is not proposing any change from the current level of 7 revenue requirement resulting from Docket No. 37744. The last 8 decommissioning cost estimate was completed in 2009 and per the rule a 9 cost estimate is only required every five years. The Company’s proposal 10 to request no change in the revenue requirement is further supported by 11 the August 9, 2011 letter from the Nuclear Regulatory Commission 12 included as Exhibit MPC-2 to my testimony. 13 14 K. Schedule P – Class Cost of Service Analysis 15 Q. PLEASE DESCRIBE SCHEDULE P-10. 16 A. Schedule P-10 provides adjusted O&M payroll by account for the test 17 year. The information is categorized by Company, affiliates, and total. 18 19 L. Schedule S – Test Year Review 20 Q. PLEASE DESCRIBE SCHEDULE S. 21 A. Schedule S consists of a report by ETI's independent certified public 22 accountants (“CPAs”), Deloitte & Touche, on a review covering the test 2011 ETI Rate Case 3-341 Entergy Texas, Inc. Page 59 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 year which complies with applicable standards established by the 2 American Institute of CPAs and with the procedures detailed in the RFP. 3 4 Q. PLEASE DESCRIBE THE SCHEDULE S-1 SERIES. 5 A. Schedules S, S-1a, and S-1b include a description summarizing the 6 independent accountants' scope of review procedures and materiality 7 considerations applied to each of the required minimum procedures listed 8 in the RFP instructions for Schedule S. 9 10 Q. PLEASE DESCRIBE SCHEDULE S-2. 11 A. Schedule S-2 indicates that there were no material errors, exceptions, or 12 omissions noted by Deloitte & Touche during the course of the test year 13 review. 14 15 Q. PLEASE DESCRIBE THE SCHEDULE S-3 SERIES. 16 A. Schedules S-3 and S-3a indicate there were no communications by the 17 independent accountants on reportable conditions required by Statement 18 on Auditing Standards No. 60, Communication of Internal Control 19 Structure Related Matters Noted in an Audit. 20 21 Q. PLEASE DESCRIBE SCHEDULE S-4. 22 A. Schedule S-4 requires a copy of adjusting journal entries resulting from 23 the most recent annual audit provided by Deloitte & Touche to ETI for 2011 ETI Rate Case 3-342 Entergy Texas, Inc. Page 60 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 posting to ETI's books. There were no such entries for ETI as the result of 2 the most recent audit. 3 4 Q. PLEASE DESCRIBE SCHEDULE S-5. 5 A. Schedule S-5 includes a copy of all potential or passed adjusting journal 6 entries identified during the course of the most recent annual audit that 7 were not posted to ETI's books. 8 9 Q. PLEASE DESCRIBE SCHEDULE S-6. 10 A. Schedule S-6 requires the name and telephone number of a contact 11 person through whom arrangements can be made to review Deloitte & 12 Touche’s workpapers for the test year review and the most recent annual 13 audit. This schedule also specifies a location in Austin, Texas, where the 14 workpapers will be made available for review. 15 16 VI. RATE CASE EXPENSES 17 Q. WHAT IS THE COMPANY'S ESTIMATE OF RATE CASE EXPENSES 18 ASSOCIATED WITH THIS PROCEEDING? 19 A. Schedule G-14.1 reflects the estimated rate case expenses that the 20 Company will incur in connection with this rate proceeding. Total 21 estimated expenses, including expenses of Cities, are $12,350,000 as 22 shown on page 1. The estimated expenses are based on the assumption 23 the case is litigated and reflect estimated expenses to obtain a final order 2011 ETI Rate Case 3-343 Entergy Texas, Inc. Page 61 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 from the PUC. The Company will collect actual expenses related to this 2 case and submit the expense amounts, along with supporting testimony, 3 in accordance with the procedural schedule ultimately adopted by the 4 Administrative Law Judge. 5 6 Q. ARE COSTS OF ESI INCLUDED IN RATE CASE EXPENSE? 7 A. Yes. ETI uses the services of ESI in preparing rate filings. Employees of 8 ESI, such as myself, were required and needed to provide support or 9 testimony in this proceeding. 10 11 Q. PLEASE DESCRIBE THE PROCEDURE FOR REVIEWING THE 12 COMPANY’S ACTUAL RATE CASE EXPENSES. 13 A. There are a number of consultants and outside lawyers involved in 14 preparing this rate case. The consultants have been retained by ESI or 15 the Company or have been retained by legal counsel representing the 16 Company to provide specialized work needed to support the rate filing. 17 When billings are received from the consultants or through legal 18 counsel, the appropriate personnel review the charges and approve them 19 for payment. The bill is then forwarded to Accounts Payable for payment. 20 Accounts Payable personnel review each bill submitted for payment to 21 determine that proper approval has been made. 2011 ETI Rate Case 3-344 Entergy Texas, Inc. Page 62 of 62 Direct Testimony of Michael P. Considine 2011 Rate Case 1 Q. HOW DOES THE COMPANY PROPOSE TO RECOVER RATE CASE 2 EXPENSES? 3 A. The Company proposes that it be permitted to recover these costs over a 4 three-year period, with a return on the unamortized balance. 5 6 VII. CONCLUSION 7 Q. PLEASE STATE YOUR CONCLUSIONS. 8 A. The Company's requested cost of service and rate base are an accurate 9 reflection of the Company's reasonable and necessary costs as 10 appropriately adjusted and presented in accordance with the PUC's 11 Substantive Rules. Additionally, the adjustments contained in the 12 Company’s filing are appropriate and reflect the regulatory treatment 13 intended. 14 15 Q. DOES THIS CONCLUDE YOUR PREFILED DIRECT TESTIMONY? 16 A. Yes. 2011 ETI Rate Case 3-345 This page has been intentionally left blank. 2011 ETI Rate Case 3-346 Exhibit MPC-1 2011 TX Rate Case Page 1 of 5 Entergy Texas, Inc. Listing of Rate Filing Package Schedules Sponsored Or Co-Sponsored By Michael P. Considine Line No. Schedule Description Sponsor Co-Sponsor 1 A-4 Detail TYE Trial Balance X 2 B-1 Rate Base & Return-Total Co X 3 B-1.2 % Of Plant In Service X 4 B-1.3 Penalties Or Fines X 5 B-1.4 Post Test Year Adjustments X 6 B-2 Accumulated Provision Balances X 7 B-2.1 Accumulated Provision Policies X 8 C-1 Original Cost of Utility Plan X 9 C-2 Detail Of Orig Cost Of Util Plant X 10 C-3 Monthly Detail Of Util Plt In Svc X 11 C-4.1 CWIP By Functional Group X 12 C-4.2 CWIP Allowed In Rate Base X 13 C-5 AFUDC or IDC X 14 C-6 Nuclear Fuel X 15 C-6.1 Nuclear Fuel in Process X 16 C-6.2 Distrib Of Costs & Qnts-A/C 120-1 X 17 C-6.3 Distrib Of Costs & Qnts-A/C 120.2 X 18 C-6.4 Distrib Of Costs & Qnts-A/C 120.3 X 19 C-6.5 Distrib Of Costs & Qnts-A/C 120.4 X 20 C-6.6 Distrib Of Costs & Qnts-A/C 120.5 X 21 C-6.7 Distrib Of Costs & Qnts-A/C 120.6 X 22 C-6.8 Allocation Of Unassigned Balance X 23 C-6.9 Nuclear Fuel Inventory Policy X 24 C-6.10 Nuclear Fuel Trust/Lease X 25 D Narrative-Accum Depr Sect As Spcfd X 26 D-1 Accum Dpr By Funct Grp/Prim A/C X 27 D-2 Accum Dpr BookingMethods X 28 D-3 Plant Held For Future Use X 29 D-4 Depreciation Expense X 30 D-5 Depreciation Rate Study X 2011 ETI Rate Case 3-347 Exhibit MPC-1 2011 TX Rate Case Page 2 of 5 Entergy Texas, Inc. Listing of Rate Filing Package Schedules Sponsored Or Co-Sponsored By Michael P. Considine Line No. Schedule Description Sponsor Co-Sponsor 31 D-6 Retirement Data for All Generating Units X 32 D-7 Summary Of Book Salvage X 33 D-8 Service Lives X 34 E-1 Monthly Blnces-Short Term Assets X 35 E-1.1 Detail Of Short Term Assets X 36 E-1.2 Obsolete Assets X 37 E-1.3 Short Term Assets Policies X 38 E-2.2 Fossil Fuel Inventory Evaluation X 39 E-2.3 Fossil Fuel Inventories X 40 E-2.4 Fossil Fuel Inventory Levels X 41 E-4 Working Cash Allowance X 42 E-5 Prepaymnts + Matrls & Supplies X 43 E-6 Customer Deposits X 44 G-1 Payroll Information X 45 G-1.1 Regular * Overtime Payroll X 46 G-1.2 Regular Payroll By Category X 47 G-1.3 Payroll Capitalized vs. Expenses X 48 G-1.4 Payroll By Company X 49 G-1.6 Payments Oth Than Standard Pay X 50 G-2.1 Pension Expense X 51 G-2.2 Postretirement Benefits Excl Pens X 52 G-3 Bad Debt Expense X 53 G-4 Summ Of Adtsng, Contrbtns, Dues X 54 G-4.1 Summary Of Advertising Expense X 55 G-4.1a Summ Of Inform/;instruct Advtsng X 56 G-4.1b Advtsng Summ-Promote/Rtn Use X 57 G-4.1c Summ Of General Advtsng Exp X 58 G-4.1d Capitalized Advertising X 59 G-4.2 Summ-Contrbtn & Donation Exp X 60 G-4.2a Summ-Educat Contrbtns/Dontns X 2011 ETI Rate Case 3-348 Exhibit MPC-1 2011 TX Rate Case Page 3 of 5 Entergy Texas, Inc. Listing of Rate Filing Package Schedules Sponsored Or Co-Sponsored By Michael P. Considine Line No. Schedule Description Sponsor Co-Sponsor 61 G-4.2b Summ-Commun Svc Contr/Dontns X 62 G-4.2c Summ-Econ Dvlpmnt Contr/Dontns X 63 G-4.3 Summary-Membership Dues Exp X 64 G-4.3a Summary-Industry Organztn Dues X 65 G-4.3b Summ-Business/Economic Dues X 66 G-4.3c Summary-Professional Dues X 67 G-4.3d Summ-Socl/Recrtnl/Fratnl/Relgs Exp X 68 G-4.3e Summ-Political Organztns Exp X 69 G-5 Summ-Exclsns From Test Yr Exp X 70 G-5.1 Analysis Of Legislative Advocacy X 71 G-5.1a Payments To Registrd Lobbyists X 72 G-5.1b Payments For Monitoring Legislatn X 73 G-5.2 Summary Of Penalities & Fines X 74 G-5.3 Other Exclusions X 75 G-5.4 Analysis Of Prior Rt Case Exclsns X 76 G-5.5 Comprsn-Pr Rt Cse Excl To Currnt X 77 G-7.1 Recon-Test Yr Bk Net Inc & Tax Net Inc X 78 G-7.2 Plant Adjustments X 79 G-7.4 ADFIT X 80 G-7.4b Adjustments to ADFIT X 81 G-7.4c ADFIT & ITC-Plt Adjstmnts & Alloc X 82 G-7.4d ADFIT-Rate Case Expense X 83 G-7.5c ITC Utilized-Stand Alone Basis X 84 G-7.5e FERC A/C 255 Balance X 85 G-7.6 Analys-TY & Rqstd FIT-Tx Meth 2 X 86 G-7.6a Analysis Of Deferred FIT X 87 G-7.7 Analysis Of Addtnl Deprec Rqstd X 88 G-7.8 Analys-TV & Rqstd FIT-Tx Meth 1 X 89 G-7.10 Effects Of Acctng Order Deferrals X 90 G-7.11 Effct-Post TY Adjust-FIT & ADFIT X 2011 ETI Rate Case 3-349 Exhibit MPC-1 2011 TX Rate Case Page 4 of 5 Entergy Texas, Inc. Listing of Rate Filing Package Schedules Sponsored Or Co-Sponsored By Michael P. Considine Line No. Schedule Description Sponsor Co-Sponsor 91 G-7.12 Effcts-Rt Modrtn Plan-FIT & ADFIT X 92 G-7.12a Trtmnt=FIT/ADFIT in Rt Modrtn Pln X 93 G-7.13 List of FIT/ADFIT Testimony X 94 G-8 Outside Svcs Emp-FERC 900 Exp X 95 G-9 Taxes Oth Than Inc Taxes (UR X 96 G-9.1 Ad Valorem Txs & Plt Balances X 97 G-10 Factoring Expense (UR) X 98 G-11 Def Expenses From Prior Dckts X 99 G-12 Below The Line Expenses X 100 G-13 Nonrecurring Or Extrdnry Exp X 101 G-14 Regulatory Commission Exp X 102 G-14.1 Rate Case Expenses X 103 G-14.2 Rate Case Exp-Pr Rate Applctns X 104 G-15 Monthly O&M Expense X 105 H-1 Summ Of Test Yr Prod O&M Exp X 106 H-1.1 Nucl Co-Wide O&M Exp Summary X 107 H-1.1a Nucl Plt O&M Summary X 108 H-1.1a1 Nucl Unit O&M Summary X 109 H-1.2 Fossil Co-Wide O&M Exp Summ X 110 H-1.2a Nat Gas Plt O&M Summary X 111 H-1.2a1 Natural Gas (Steam Genrtn) X 112 H-1.2a2 Natural Gas (Combustn Turbine) X 113 H-1.2b Coal Plant O&M Summary X 114 H-1.2c Lignite Plant O&M Summary X 115 H-1.2d Oth Plant O&M Summary X 116 H-2 Summ-Adjstd TY Prod O&M Exp X 117 H-3 Summary-Act. Prod. O&M Exp Incurred X 118 H-5.1 Prod Plt Capital Cost Methodology X 119 H-10 Nucl Decommiss Cost Studies X 120 J Financial Statements X 2011 ETI Rate Case 3-350 Exhibit MPC-1 2011 TX Rate Case Page 5 of 5 Entergy Texas, Inc. Listing of Rate Filing Package Schedules Sponsored Or Co-Sponsored By Michael P. Considine Line No. Schedule Description Sponsor Co-Sponsor 121 J-1 Reconciliation-Total Co To Total Elec X 122 J-2 Consolidated Finance Statements X 123 K-1 Weighted Avg Cost Of Capital X 124 K-2 Wghtd Avg Cost Of Preferred Stock X 125 K-3 Wghtd Avg Cost Of Debt X 126 K-4 Notes Payable X 127 K-5 Security Issuance Restrictions X 128 K-6 Financial Ratios X 129 P-10 Payroll Expense Distribution X 130 S Test Yr Review As Specfd X 131 S-1 Scope Of Review X 132 S-2 Errors/Excptns Noted-Indp Accnts X 133 S-3 Communictns From Indept Accnts X 134 S-4 Adjusting Journal Entries X 135 S-5 Passed Adjstng Journal X 136 S-6 Workpaper Review-Indep Acctnts X 2011 ETI Rate Case 3-351 This page has been intentionally left blank. 2011 ETI Rate Case 3-352 Exhibit MPC-2 2011 TX Rate Case Page 1 of 3 UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON , O.C. 20555-0001 August 9 2011 1 Vice President, Operations Entergy Operations, Inc. River Bend Station 5485 U.S. Highway 61 N St. Francisville, LA 70775 SUBJECT: ENTERGY GULF STATES LOUISIANA, LLC 'S STATUS OF DECOMMISSIONING FUNDING ASSURANCE FOR RIVER BEND STATION, UNIT 1 (70 PERCENT REGULATED) (TAC NO. ME5526) Dear Sir or Madam: By letter dated March 31 , 2011 (Agencywide Documents Access and Management System Accession No. ML 110940138), Entergy Operations, Inc. (the licensee), submitted the biennial decommissioning funding report for River Bend Station (RBS) for both the regulated portion of the unit (70 percent) and the unregulated portion of the unit (30 percent). The U.S. Nuclear Regulatory Commission (NRC) staff has concluded that the 30 percent non- regulated portion of RBS meets the required minimum funding criteria of Title 10 of the Code of Federal Regulations (10 CFR) 50.75(b) and (c) based on the current funding level of the decommissioning trust fund , length of time remaining on the license, and expected earnings on the trust fund balance. The NRC staff has concluded that the 70 percent rate-regulated portion of RBS meets the required minimum funding criteria of 10 CFR 50.75(b) and (c) based on its current funding level, length of time remaining on the license, expected earnings on the trust fund , and future collections to the trust fund from the Louisiana Public Service Commission (LPSC) and the Public Utilities Commission of Texas (PUCT). For the regulated portion of RBS (70 percent), the licensee submitted orders from the LPSC and PUCT approving decommissioning trust fund collections through 2034 for RBS . The NRC has concluded that RBS is on track to have sufficient funds for decommissioning at the time of permanent termination of operations is expected. As such, we consider our review of the decommissioning funding report complete with the issuance this letter. Paperwork Reduction Act Statement This letter does not contain any new or amended information collection requirements subject to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq .). Existing collection requirements under 10 CFR Part 50 were approved by the Office of Management and Budget (OMB), control number 3150-0011 , which expires August 31 , 2013. 2011 ETI Rate Case 3-353 Exhibit MPC-2 2011 TX Rate Case Page 2 of 3 -2- Public Protection Notification The NRC may not conduct or sponsor, and a person is not required to respond to, an information collection unless the requesting document displays a currently valid OMS control number. If you have any questions regarding this review, please contact me at alan.wang@nrc.gov or (301) 415-1445. Sincerely, ~vJ~ Alan B. Wang, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-458 cc: Distribution via Listserv 2011 ETI Rate Case 3-354 Exhibit MPC-2 2011 TX Rate Case Page 3 of 3 -2- Public Protection Notification The NRC may not conduct or sponsor, and a person is not required to respond to , an information collection unless the requesting document displays a currently valid OMS control number. If you have any questions regarding this review, please contact me at alan.wang@nrc.gov or (301) 415-1445. Sincerely, /RAJ Alan 8. Wang , Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-458 cc : Distribution via Listserv DISTRIBUTION : PUBLIC LPUV r/f RidsAcrsAcnw_MailCTR Resource RidsNrrDprPfpb Resource RidsNrrDorllpl4 Resource RidsNrrLAJBurkhardt Resource RidsNrrPMRiverBend Resource RidsOgcRp Resource RidsRgn4Mai1Center Resource MDusaniwskyj, NRR/DPR/PFPB TFredrichs, NRR/DPR/PFPB SUttal, OGC ADAMS Accession No. ML112010507 *memo dated OFFICE NRR/L PL4/PM NRR/LPL4/ LA NRR/DPR/PFPB/BC OGC NLO NRR/LPL4/BC NRR/LPL4/PM AWang (LWilkins AWang ... CRegan ASimmons tor" SUttal MMarkley for) --NAME DAT E 7/25/11 JBurkhardt 7/21/11 7/15/1 1 7128/1 1 8/9/ 11 8/9/11 OFFICIAL AGENCY RECORD 2011 ETI Rate Case 3-355 This page has been intentionally left blank. 2011 ETI Rate Case 3-356 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 ETI 2011 Rate Case ETI EXHIBIT NO. 15 DOCKET NO. 39896 APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION TEXAS, INC. FOR AUTHORITY § TO CHANGE RATES AND § OF TEXAS RECONCILE FUEL COSTS § DIRECT TESTIMONY OF JAY C. HARTZELL, Ph.D. ON BEHALF OF ENTERGY TEXAS, INC. NOVEMBER 2011 2011 ETI Rate Case 5-1 ENTERGY TEXAS, INC. DIRECT TESTIMONY OF JAY C. HARTZELL, Ph.D. 2011 RATE CASE TABLE OF CONTENTS Page I. Background and Introduction 1 II. Overview of the Issues Surrounding Incentive Compensation 3 III. The False Dichotomy Between Compensation Tied to "Financial" Measures and Compensation Tied to "Operational" Measures; and the Benefits of Cost Control, Profitability, and Stock Price Measures 9 IV. Costs to Customers of Discouraging the Use of Incentive Compensation That is Linked to Cost Control, Profitability and Stock Prices 22 V. Response to Common Arguments Against Incentive Compensation Linked to Cost Control, Profitability and Stock Prices from the Customers' Perspective 28 VI. Conclusion 31 EXHIBITS EXHIBIT JCH-1 Curriculum Vitae of Jay C. Hartzell 2011 ETI Rate Case 5-2 Entergy Texas, Inc. Page 1 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 I. BACKGROUND AND INTRODUCTION 2 Q. PLEASE STATE YOUR NAME, TITLE, AND BUSINESS ADDRESS. 3 A. My name is Jay C. Hartzell. I am the Chair of the Finance Department, 4 Professor of Finance, and the Allied Bancshares Centennial Fellow at the 5 McCombs School of Business at the University of Texas at Austin. My 6 business address is Department of Finance, The University of Texas at 7 Austin, 1 University Station B6600, Austin, Texas 78712. 8 9 Q. ON WHOSE BEHALF ARE YOU TESTIFYING? 10 A. I am testifying on behalf of Entergy Texas, Inc. ("ETI" or the "Company"). 11 12 Q. PLEASE STATE YOUR EDUCATION, PROFESSIONAL AND WORK 13 EXPERIENCE. 14 A. I obtained a Bachelor of Science degree (cum laude) from Trinity 15 University in May 1991, with majors in Business Administration and 16 Economics. After graduating, I went to work as a consultant for Hewitt 17 Associates in The Woodlands, Texas. Hewitt is a consulting firm that 18 specializes in benefits and compensation. While there, I specialized in the 19 area of defined contribution plans. I left Hewitt to go to graduate school at 20 the University of Texas at Austin in 1993. I completed my PhD in finance 21 there in May 1998. Upon graduating, I took a job as an Assistant 22 Professor of Finance at New York University's Stern School of Business, 23 where I worked until 2001. At that time, the University of Texas at Austin 2011 ETI Rate Case 5-3 Entergy Texas, Inc. Page 2 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 hired me as an Assistant Professor at the McCombs School of Business 2 ("McCombs School"), where I have worked since. I was promoted to the 3 rank of Associate Professor (with tenure), effective in the fall of 2006. 4 Beginning in the fall of 2008, I was given the title of Allied Bancshares 5 Centennial Fellow. I also now serve as the Executive Director of the Real 6 Estate Finance and Investment Center at the McCombs School. As of 7 September 2011, I was promoted to Professor and assumed the duties of 8 the Chair of the Finance Department. My current curriculum vitae is 9 attached as Exhibit JCH-1. 10 11 Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE A REGULATORY 12 COMMISSION? 13 A. Yes. I have submitted written testimony on incentive compensation issues 14 and testified on behalf of the Company before the Public Utility 15 Commission of Texas ("Commission" or "PUCT") in PUCT Docket Nos. 16 34800 and 37744, and on behalf of Entergy Louisiana, LLC before the 17 Louisiana Public Service Commission on incentive compensation issues in 18 Docket No. U-20925. I have also submitted written testimony on behalf of 19 Entergy Arkansas, Inc. before the Arkansas Public Service Commission 20 on incentive compensation issues in Docket No. 09-084-U. 2011 ETI Rate Case 5-4 Entergy Texas, Inc. Page 3 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 II. OVERVIEW OF THE ISSUES SURROUNDING INCENTIVE 2 COMPENSATION 3 Q. WHAT FORMS OF INCENTIVE COMPENSATION DO YOU FOCUS ON 4 IN YOUR TESTIMONY? 5 A. The focus of my testimony is on incentive compensation that is linked to 6 cost control measures (for operating costs and capital expenditures), 7 profitability measures (including earnings and operating cash flow), and 8 stock prices. Compensation that is linked to these sorts of measures – for 9 companies generally and for ETI in particular – include annual incentive 10 plans, long-term incentive plans, restricted stock grants, and stock option 11 grants. The compensation could come in the form of cash (as in annual 12 incentive plans), stock or stock-based units (as in ETI's long-term 13 incentive plan, or "LTIP"), or options. 14 15 Q. WHAT IS YOUR UNDERSTANDING OF HOW COMPENSATION BASED 16 ON COST CONTROLS, PROFITABILITY AND STOCK PRICES HAS 17 BEEN CHARACTERIZED IN RECENT PUCT RATE DECISIONS? 18 A. In such cases, compensation that is linked to cost controls, profitability 19 and stock prices as discussed in the previous question has commonly 20 been referred to as incentive compensation that is based on "financial 21 measures." This category of incentives has been distinguished from 22 incentive compensation that is based on measures that are not 23 denominated in dollars, such as customer satisfaction, reliability, and 2011 ETI Rate Case 5-5 Entergy Texas, Inc. Page 4 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 safety metrics, which has commonly been categorized as incentive 2 compensation based on "operational measures." As I discuss later in my 3 testimony, I view this as a false dichotomy for the purposes of assessing 4 whether customers benefit from a particular form of incentive 5 compensation. 6 7 Q. WHY DO FIRMS USE INCENTIVE COMPENSATION IN GENERAL, AND 8 COMPENSATION BASED ON COST CONTROLS, PROFITABILITY AND 9 STOCK PRICES MORE SPECIFICALLY? 10 A. Incentive compensation is a prevalent tool used to attract, motivate, and 11 retain the qualified and talented employees needed to ensure that a 12 business can continue to operate successfully. To understand why it is so 13 widely used, it is first useful to draw a distinction between the level and 14 form of compensation. The level of compensation can be thought of as 15 the total dollar value of compensation received by an employee from all 16 sources, including salary, cash incentive-based pay, the value of 17 long-term incentives such as stock performance units and options granted, 18 and the value of benefits. In order to attract and retain employees, this 19 level needs to be in line with the labor market for a particular type of 20 employee, whether it is an engineer, a maintenance worker, or a chief 21 executive officer. Otherwise, all things equal, that same employee will 22 take a job with a company that is offering the more attractive level of pay 2011 ETI Rate Case 5-6 Entergy Texas, Inc. Page 5 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 and benefits. Company witness Kevin G. Gardner discusses the overall 2 reasonableness of ETI's level of compensation in his direct testimony. 3 4 Q. HOW DOES THE FORM OF COMPENSATION DIFFER FROM THE 5 LEVEL OF COMPENSATION? 6 A. The form of compensation can be thought of as the split of total 7 compensation across these components – for example, how much is paid 8 via salary versus annual incentive-based compensation. Holding the total 9 level of compensation fixed at the proper market level, the form of 10 compensation is important because it can help motivate employees to 11 engage in behaviors that positively impact the operational efficiency of the 12 firm, or positively affect its cost structure. At the same time, the form of 13 compensation is important to attract and retain certain types of employees 14 that offer a skill set or a particular talent that is important to the company's 15 operations. For example, if a compensation plan provides for incentive 16 payments if goals are met – such as controlling costs at some level – then 17 according to basic economic theory, employees will be motivated to work 18 harder toward those goals. More subtly, such incentive pay will tend to 19 attract and retain employees who believe that they are especially good at 20 controlling costs because they will expect higher compensation under 21 such a plan. This implies that a firm seeking to manage costs will find it 22 valuable to institute such an incentive compensation plan as part of the 2011 ETI Rate Case 5-7 Entergy Texas, Inc. Page 6 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 design of the form of compensation, while keeping the level of 2 compensation at a competitive market-based amount. 3 4 Q. WHAT IS YOUR UNDERSTANDING OF THE COMMISSION'S 5 PREVIOUS VIEW ON ALLOWING THE RECOVERY OF INCENTIVE 6 COMPENSATION EXPENSE THROUGH RATES? 7 A. My understanding of the Commission's recent rulings on this issue is that 8 the Commission has distinguished between compensation tied to what it 9 has termed operational measures and compensation tied to what it has 10 termed financial measures. Generally, the Commission has not allowed 11 for the recovery of incentive compensation tied to financial measures 12 through rates, but has allowed for the recovery of incentive compensation 13 tied to operational measures. The core rationale for this distinction has 14 been that it has not been sufficiently demonstrated that incentive 15 compensation linked to financial measures is in the public interest or of 16 direct benefit to customers. The decisions in those previous cases, 17 however, do not reflect a review or consideration of the relevant literature 18 or other matters I discuss below, all of which support a conclusion that 19 allowing utilities to use incentive pay based on cost control, profitability, 20 and stock prices is properly viewed as in the public interest and is 21 expected to be of direct benefit to customers. 2011 ETI Rate Case 5-8 Entergy Texas, Inc. Page 7 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 Q. HOW WOULD YOU SUMMARIZE YOUR OPINION ON THE ISSUE OF 2 WHETHER INCENTIVE COMPENSATION BASED ON COST 3 CONTROLS, PROFITABILITY, AND STOCK PRICES BENEFITS 4 CUSTOMERS? 5 A. In my opinion, a well-designed compensation plan that includes incentive 6 compensation tied to cost controls, profitability, and stock prices would 7 tend to provide greater benefits to customers than an otherwise similar 8 compensation plan that did not include any such incentive compensation. 9 I discuss the details below, but the overarching basis for my opinion is as 10 stated above: incentive compensation based on cost control, profitability, 11 and stock prices helps companies attract, motivate, and retain talented 12 employees, and by doing so, both customers and shareholders directly 13 benefit. Moreover, if ETI's incentive compensation were only based on 14 non-dollar-based measures such as safety and reliability, customers 15 would tend to be worse off, because such a plan would not provide 16 employees with incentives to look after the financial health of the 17 Company. The important point is that customers and shareholders both 18 benefit from well-designed, balanced compensation plans that provide 19 employees with the appropriate level of compensation and that include 20 incentives based on cost control, profitability, stock prices, and 21 non-dollar-based measures such as reliability, safety and customer 22 satisfaction. 2011 ETI Rate Case 5-9 Entergy Texas, Inc. Page 8 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 Q. IS YOUR OPINION THAT CUSTOMERS WILL TEND TO BENEFIT 2 FROM INCENTIVE COMPENSATION TIED TO COST CONTROLS, 3 PROFITABILITY AND STOCK PRICES SUPPORTED BY EMPIRICAL 4 EVIDENCE? 5 A. Yes. As I discuss in more detail below, there are multiple studies 6 published in peer-reviewed journals that report evidence that is consistent 7 with my testimony. Published empirical research has shown that workers 8 respond to incentive plans in a manner consistent with the intent behind 9 the plans' design. Thus, if a company adopts a compensation plan that 10 includes incentives based on customer welfare and stock price, one can 11 expect managers to take actions to improve customer welfare and 12 maximize stock price (holding all else equal). There is also empirical 13 evidence that following the adoption of long-term incentive plans that 14 provide for stock-based compensation, managers’ interests appear more 15 closely aligned with those of the firms’ customers. In addition, there is 16 evidence that stockholders’ and customers’ interests tend to be aligned, 17 rather than opposed, suggesting that incentive compensation linked to 18 stock prices is likely to improve customer satisfaction rather than detract 19 from it. 2011 ETI Rate Case 5-10 Entergy Texas, Inc. Page 9 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 III. THE FALSE DICHOTOMY BETWEEN COMPENSATION TIED TO 2 "FINANCIAL" MEASURES AND COMPENSATION TIED TO 3 "OPERATIONAL" MEASURES; AND THE BENEFITS OF COST 4 CONTROL, PROFITABILITY, AND STOCK PRICE MEASURES 5 Q. DO YOU AGREE WITH THE OPINION THAT INCENTIVE 6 COMPENSATION LINKED TO WHAT THE COMMISSION HAS TERMED 7 "FINANCIAL MEASURES" DOES NOT PROVIDE DIRECT BENEFITS TO 8 CUSTOMERS? 9 A. No. Based on its previous rulings, the Commission appears to be 10 categorizing as "financial" all incentive performance measures that have 11 been labeled as such by the utility and that are based on dollar amounts. 12 These include not only measures such as earnings per share, but also 13 measures designed to promote cost containment.1 In reading these 14 decisions and the debates among the parties discussed therein, much of 15 the discussion seems to take it as given that incentives linked to financial 16 (or dollar-based) measures, regardless of their specific characteristics, do 17 not benefit customers. As a result, the competing viewpoints reflected in 18 these decisions seem to address mainly whether to label particular 19 measures as operational or financial.2 20 Instead of focusing on whether a particular measure is dollar-based 21 or not – and therefore, whether incentives linked to that measure are 22 "financial" or "operational" based on the above dichotomy – I think it is 1 For example, see PUCT Docket No. 28840, PFD at 78. 2 For example, see PUCT Docket No. 35717, PFD at 98. 2011 ETI Rate Case 5-11 Entergy Texas, Inc. Page 10 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 more worthwhile to return to the primary question: whether specific 2 incentives linked to dollar-based measures (including cost control, 3 profitability, and stock prices) are of benefit to customers. 4 5 Q. WHY WOULD INCENTIVE COMPENSATION LINKED TO COST 6 CONTROL, PROFITABILITY, AND STOCK PRICE MEASURES BE OF 7 DIRECT BENEFIT TO CUSTOMERS? 8 A. This is the case because these measures provide a necessary and 9 important incentive to managers to improve service and control costs. 10 Perhaps the easiest example of a dollar-based measure that could be 11 used in an incentive compensation plan that would benefit customers 12 directly is cost containment. As an example, consider an incentive 13 compensation plan that pays corporate managers an incentive award if 14 costs are suitably contained. On the one hand, such an incentive is likely 15 to benefit shareholders to some extent – managers who work under such 16 a compensation plan will work to control costs in order to achieve their 17 incentive compensation, and to the extent that they are successful, the 18 company will generate greater profits, benefiting shareholders. But 19 customers also directly benefit, because the company has lower costs, 20 and through the regulatory process, customers will ultimately pay lower 21 rates than they otherwise would have paid in the absence of such cost 22 controls. 2011 ETI Rate Case 5-12 Entergy Texas, Inc. Page 11 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 Q. WHAT IS THE ROLE OF THE REGULATORY PROCESS IN ENSURING 2 THAT INCENTIVES LINKED TO COST CONTROL BENEFIT 3 CUSTOMERS? 4 A. To understand the role of the regulatory process in linking cost control to 5 customer benefit, first consider an extreme example where there is no 6 regulatory lag and rates adjust instantaneously so that any change in a 7 utility's costs is immediately passed through to customers. In this case, a 8 cost-containment incentive clearly directly benefits customers and does 9 not benefit shareholders at all because customers reap the entire benefit 10 of any cost-saving innovations. In the other extreme, if rates never adjust 11 to changes in costs, then a cost-containment incentive benefits 12 shareholders but not customers. Thus, the regulatory process plays the 13 critical role of sharing the gains from cost controls brought about by 14 managerial incentive compensation between customers and shareholders. 15 16 Q. IS THIS POINT THAT CUSTOMERS BENEFIT FROM MANAGERIAL 17 EFFICIENCY A COMMONLY ACCEPTED TENANT OF UTILITY RATE 18 ECONOMICS? 19 A. Yes. This idea of a win-win scenario, where both shareholders and 20 customers benefit from managerial efficiency, is not new and is a core 21 idea at the heart of well-established principles of regulatory economics. 22 For example, James C. Bonbright discusses it in his seminal 1961 treatise 23 on utility economics, Principles of Public Utility Rates. 2011 ETI Rate Case 5-13 Entergy Texas, Inc. Page 12 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 Q. DO THESE PRINCIPLES APPLY TO OTHER FORMS OF INCENTIVE 2 COMPENSATION THAT ARE LINKED TO PROFITABILITY AND STOCK 3 PRICE MEASURES? 4 A. Yes. While I think that cost containment measures are the most obvious 5 example of incentives that have in some past PUCT cases been 6 categorized as "financial" and yet directly benefit customers, these 7 principles apply to other dollar-based or financial measures as well, such 8 as incentive awards tied to corporate profitability and stock prices. 9 10 Q. CAN YOU PLEASE FURTHER ELABORATE ON WHY CUSTOMERS 11 ARE LIKELY TO BENEFIT FROM COMPENSATION THAT IS LINKED 12 TO PROFITABILITY? 13 A. Yes. There is a direct link between cost containment and company 14 earnings, especially for a regulated utility. Managers with an incentive to 15 increase earnings will focus on controlling or cutting costs in a regulated 16 industry because it is more difficult to grow revenues. Additionally, the 17 same type of reasoning that supports a linkage between cost containment 18 and customer benefit also applies to incentive measures that focus on 19 containing capital expenditures. If managers can offer the same service 20 while cutting back on capital expenditures by investing more efficiently, 21 then shareholders benefit due to greater short-run cash flows for the 22 company, and customers benefit through the regulatory process through 23 lower recovery for the cost of capital due to a lower capital base. 2011 ETI Rate Case 5-14 Entergy Texas, Inc. Page 13 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 Q. WHAT TYPE OF INCENTIVE COMPENSATION DO YOU INCLUDE 2 WITHIN THE CATEGORY OF COMPENSATION THAT IS LINKED TO 3 STOCK PRICES? 4 A. This category would include most long-term incentive plans (including 5 ETI's) that use performance units that are based on stock prices, as well 6 as stock options. 7 8 Q. CAN YOU BRIEFLY SUMMARIZE WHY YOU BELIEVE THAT 9 COMPENSATION THAT IS LINKED TO STOCK PRICES BENEFITS 10 CUSTOMERS? 11 A. Compensation that is linked to stock prices has several advantages for 12 customers as long as it is part of a reasonable, well-designed 13 compensation plan – in other words, as long as the total level of 14 compensation is reasonable compared to the market for similar positions 15 and the form of compensation is well balanced across dollar-based and 16 non-dollar-based measures. First, compensation that is linked to stock 17 prices helps ensure that managers will consider the financial health of the 18 company when they make decisions, and it is in customers' interests to 19 have the company continue to be financially healthy. Second, 20 stock-based compensation provides an incentive for managers and 21 employees to ensure that the company operates efficiently, and via the 22 regulatory process, lower costs result in lower rates than would otherwise 23 occur. Third, stock-based compensation provides a monitoring 2011 ETI Rate Case 5-15 Entergy Texas, Inc. Page 14 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 mechanism for managerial decision making and the overall quality of 2 management. Fourth, there is an interaction between these effects, as the 3 capital markets will tend to reward efficient long-term investments or 4 capital expenditures that will also lead to lower costs for customers. 5 6 Q. DO THESE REASONS THAT COMPENSATION THAT IS LINKED TO 7 STOCK PRICES BENEFITS CUSTOMERS ALSO APPLY TO 8 COMPENSATION THAT IS LINKED TO COST CONTROL AND 9 PROFITABILITY? 10 A. In general, yes. Stock prices are driven in part by cost control and 11 profitability, so to the extent that managers have an incentive to increase 12 the stock price, they will also have an incentive to control costs and 13 increase profits and cash flows, and vice versa. Of the reasons listed in 14 the previous answer, the first two reasons – incentives to ensure that the 15 company is financially healthy and that it operates efficiently – are the 16 ones that are most closely shared by compensation based on cost control 17 and profitability. 2011 ETI Rate Case 5-16 Entergy Texas, Inc. Page 15 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 Q. STARTING WITH THE FIRST REASON YOU MENTIONED, WHY DOES 2 COMPENSATION THAT IS LINKED TO PROFITABILITY AND STOCK 3 PRICES BENEFIT CUSTOMERS BY IMPROVING A COMPANY'S 4 FINANCIAL HEALTH? 5 A. If compensation that is linked to profitability and stock prices gives 6 managers an incentive to increase their company's earnings, cash flows, 7 and stock price, then this will also provide them with an incentive to 8 ensure that the company remains financially healthy. Stock prices of firms 9 that are in poor financial condition – for example, that have high debt 10 relative to the value of their assets – tend to be lower, all else being equal. 11 Similarly, firms in poor financial condition tend to have lower earnings and 12 operating cash flows. A stronger financial condition will also benefit 13 customers. If a company maintains a financially healthy position, it will 14 tend to have a lower cost of capital that will in turn benefit customers 15 through lower rates. For a discussion of this effect, see Chapter 15 of 16 Investment Valuation, by Aswath Damodaran.3 In addition, the costs of 17 doing business with suppliers (of both goods and services, including labor) 18 will remain lower. For example, if a company was not in a financially 19 stable condition, suppliers would tend to demand higher prices or more 20 onerous credit terms, resulting in higher costs that would lead to higher 3 ASWATH DAMODARAN, INVESTMENT VALUATION (John Wiley & Sons, 2d ed. 2002). 2011 ETI Rate Case 5-17 Entergy Texas, Inc. Page 16 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 rates than would otherwise occur. These are often termed "indirect costs 2 of financial distress," and are a commonly accepted concept in finance. 3 4 Q. DOES EXISTING EMPIRICAL EVIDENCE SUPPORT THE OPINION 5 THAT FINANCIALLY HEALTHY FIRMS WILL TEND TO FACE LOWER 6 COSTS, WHICH WOULD BENEFIT CUSTOMERS OF A REGULATED 7 UTILITY? 8 A. Yes. There is empirical evidence that firms with lower stock prices (or that 9 are less financially healthy) face higher costs and greater risks. This 10 includes work by researchers who have shown how less financially 11 healthy companies have trouble responding to external shocks, and face 12 higher costs of doing business (through higher wages or worse terms from 13 suppliers, for example).4 These results support the financial-health 14 channel, by which stock-based incentive compensation should provide 15 direct benefits to customers. Stock-based incentive compensation 16 encourages managers to maintain a company's financial health, thus 17 leading to more efficient operations and greater cost control than would 18 otherwise occur. 4 Chris Parsons and Sheridan Titman, Capital Structure and Corporate Strategy (January 2007). The article is available at http://ssrn.com/abstract=983553. 2011 ETI Rate Case 5-18 Entergy Texas, Inc. Page 17 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 Q. ARE THERE EXAMPLES OF EXTERNAL SHOCKS IN THE UTILITY 2 INDUSTRY THAT COULD MATERIALLY IMPACT A COMPANY’S 3 FINANCIAL HEALTH? 4 A. One example of a large external shock is a severe storm or hurricane, 5 such as Hurricanes Rita and Ike that, to my understanding, had significant 6 financial impact on Entergy Companies. For example, Hurricane Ike was 7 estimated to cause ETI to incur restoration costs between $435 million 8 and $510 million.5 The ability of a company to absorb such a shock 9 without suffering from costs of distress depends on its financial health 10 (e.g., their stock price, liquidity, and debt capacity). In this way, customers 11 benefit from compensation that provides incentives for management to 12 improve the firm’s financial condition, because such incentives would tend 13 to improve the firm’s ability to withstand sizable negative events such as 14 hurricanes, without incurring excessive additional costs of financial 15 distress. 16 17 Q. CAN YOU FURTHER EXPLAIN HOW INCENTIVE COMPENSATION 18 THAT IS LINKED TO PROFITABILITY AND STOCK PRICES CAN TEND 19 TO LEAD TO LOWER COSTS FOR CUSTOMERS? 20 A. The first step is to understand that compensation linked to profitability and 21 stock prices will provide managers with an incentive to operate efficiently 5 See http://investor.shareholder.com/entergy/releasedetail.cfm?ReleaseID=337564 2011 ETI Rate Case 5-19 Entergy Texas, Inc. Page 18 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 because, by doing so, a company's profitability (including earnings and 2 cash flow) and stock price will be higher than it would otherwise be. To 3 increase stock price, management tries to maximize the present value of a 4 company's expected cash flows by minimizing expenses and the cost of 5 capital. The role of incentive compensation in motivating managers to 6 minimize the cost of capital component and the associated benefits to 7 customers were discussed earlier. A second channel provided by 8 incentive compensation that can benefit customers is the incentive to 9 maximize the company's cash flows. In a regulated environment, 10 particularly one in which promotion of sales growth is discouraged, it is 11 likely to be more difficult to increase cash flows or profits by growing 12 revenues, so management will tend to focus on efficient operations and 13 investment. 14 These lower costs will benefit shareholders in the short run, but 15 customers over the long run. This is due to the regulatory process that 16 directly links operating costs to rates. 17 18 Q. DO PUBLISHED EMPIRICAL STUDIES SUPPORT THE OPINION THAT 19 FINANCIAL PERFORMANCE, INCLUDING STOCK PRICE, IS 20 POSITIVELY RELATED TO CUSTOMER SATISFACTION GENERALLY, 21 AND FOR UTILITY FIRMS IN PARTICULAR? 22 A. Yes. There is empirical evidence in the literature that firms with higher 23 market values tend to also have higher customer satisfaction, supporting 2011 ETI Rate Case 5-20 Entergy Texas, Inc. Page 19 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 the conclusion that the goals of financial success and customer 2 satisfaction are interrelated.6 This result has been shown for a broad 3 sample of firms, but also for utilities in particular. This empirical finding is 4 inconsistent with the idea that the most profitable or valuable firms 5 become that way by cutting customer service, and instead suggests that 6 there exists positive feedback between a firm's financial performance 7 (stock price) and customers' welfare, even in the utility industry. 8 9 Q. HOW DOES COMPENSATION THAT IS LINKED TO STOCK PRICES 10 BENEFIT CUSTOMERS VIA THE MONITORING OF MANAGERIAL 11 DECISIONS? 12 A. One of the functions of the stock market and its various participants is to 13 monitor companies' management. In their efforts to properly value stocks, 14 analysts, portfolio managers, and traders follow companies and 15 continually assess the various decisions, announcements, and pieces of 16 information they produce. In doing so, they act as a monitoring device, 17 ensuring that poor decisions would be punished by a falling stock price, so 18 managers have incentives to invest the shareholders' financial resources 19 efficiently. In this manner, managers help keep customers' costs lower 6 Christopher D. Ittner and David F. Larcker, Are Nonfinancial Measures Leading Indicators of Financial Performance? An Analysis of Customer Satisfaction, 36 JOURNAL OF ACCOUNTING RESEARCH, Supplement 1998 at 1 – 35. 2011 ETI Rate Case 5-21 Entergy Texas, Inc. Page 20 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 than they might otherwise be in the absence of such monitoring, and 2 improve the overall quality of service. 3 4 Q. DOES PUBLISHED EMPIRICAL EVIDENCE SUPPORT THE OPINION 5 THAT STOCK MARKET PARTICIPANTS MONITOR MANAGERIAL 6 DECISIONS? 7 A. Yes. There are published empirical studies that provide support for my 8 opinion that stock-based incentive compensation provides benefits to 9 customers via the monitoring of managerial decisions. An example of 10 such evidence is a study that shows that institutional investors can help 11 ensure that management does not act myopically to cut research and 12 development expenditures in order to meet short-term earnings targets.7 13 Thus, the presence of stock-based compensation that provides incentives 14 for management to respond to monitoring by stock-market participants 15 and investors can benefit customers by encouraging managers to focus 16 beyond the short term and think about long-term efficient investments. 17 18 Q. HOW DO THESE INVESTMENT AND COST EFFECTS INTERACT DUE 19 TO THE STOCK MARKET? 20 A. An important role for stock-based compensation is to encourage 21 managers to refrain from sacrificing long-run success in pursuit of 7 Brian J. Bushee, The Influence of Institutional Investors on Myopic R&D Investment Behavior, 73 THE ACCOUNTING REVIEW, 3 at 305-333 (July 1998). 2011 ETI Rate Case 5-22 Entergy Texas, Inc. Page 21 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 short-term profit.8 Stock prices are based not just on a company's 2 performance in the current year, but also on the market's expectations 3 about a company's future performance over many years. This ensures 4 that good investments tend to increase stock prices, even though those 5 investments use cash today in order to produce greater cash flows in the 6 future. This is a critical advantage of stock-based compensation over 7 annual incentive plans that are based on a particular year's (or a few 8 years') performance. Stock-based compensation can help overcome 9 managerial myopia and provide managers with an incentive to make 10 efficient, long-term investments that benefit both customers (due to 11 efficient investments that lead to lower costs) and shareholders (due to 12 higher cash flows). In this case, the testimony of Company witnesses 13 Joseph F. Domino and Chris E. Barrilleaux addressing the Company's 14 expected future capital investments, and that of Company witness Robert 15 R. Cooper regarding long-term resource planning, provide examples of 16 such consideration. 8 For example, see M.P. Narayanan, Form of Compensation and Managerial Decision Horizon, 31 JOURNAL OF FINANCIAL AND QUANTITATIVE ANALYSIS, 4 at 467-491 (1996). 2011 ETI Rate Case 5-23 Entergy Texas, Inc. Page 22 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 IV. COSTS TO CUSTOMERS OF DISCOURAGING THE USE OF 2 INCENTIVE COMPENSATION THAT IS LINKED TO COST CONTROL, 3 PROFITABILITY AND STOCK PRICES 4 Q. WHILE YOUR EARLIER TESTIMONY DISCUSSED THE BENEFITS TO 5 CUSTOMERS OF USING INCENTIVE COMPENSATION THAT IS 6 LINKED TO COST CONTROL, PROFITABILITY AND STOCK PRICES, 7 ARE THERE ALSO NEGATIVE IMPACTS TO CUSTOMERS OF NOT 8 USING STOCK-BASED COMPENSATION? 9 A. Yes. In my opinion customers would be adversely affected if ETI did not 10 include such incentive compensation in its overall compensation policy. 11 12 Q. STARTING WITH AN EXTREME EXAMPLE OF A COMPENSATION 13 POLICY WHERE ALL EMPLOYEES WERE ONLY PAID WITH 14 SALARIES, CAN YOU HIGHLIGHT THE IMPACT TO CUSTOMERS OF 15 SUCH A POLICY? 16 A. Yes. First, it is useful to note that if employees did not receive any 17 incentive compensation, salaries would have to be much higher to attract 18 and retain the same quality of talent. Second, costs would likely rise and 19 employee performance would likely suffer, as it would be difficult to 20 effectively and efficiently motivate employees to take actions that would 21 benefit shareholders and customers. In my opinion, customers would be 22 worse off under such a policy. This is supported by the principle that 23 individuals respond to incentives (a basic tenet of economics), and by 2011 ETI Rate Case 5-24 Entergy Texas, Inc. Page 23 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 empirical work that shows workers' output responds to the institution of an 2 incentive plan.9 3 4 Q. WOULD CUSTOMER INTERESTS BE ADVERSELY AFFECTED IF A 5 COMPANY USED SALARY AND INCENTIVES LINKED TO MEASURES 6 THAT HAVE BEEN TERMED "OPERATIONAL" ONLY? IN OTHER 7 WORDS, IF THEY PROVIDED SALARY AND INCENTIVES BASED ON 8 MEASURES LIKE RELIABILITY AND SAFETY, BUT NO INCENTIVES 9 BASED ON COST CONTROL, PROFITABILITY AND STOCK PRICES? 10 A. Yes. I believe customers would be worse off under such a compensation 11 policy. On the one hand, incentives linked to what have been termed 12 "operational" measures can improve customer welfare because the 13 company can better attract, motivate and retain talented employees. 14 Compared to the hypothetical case where a company compensates its 15 employees with salary only, by using salary and incentives linked to, for 16 example, safety or reliability, the company can pay less in salary and use 17 the associated savings to contribute to the annual incentive plans. On the 18 other hand, such a compensation plan still has substantial problems in the 19 context of customer benefits. 20 First, there is still no free lunch. In order for the firm to compete in 21 the market for labor, the level of employees' total compensation – even if it 9 Edward P. Lazear, Performance Pay and Productivity, 90 THE AMERICAN ECONOMIC REVIEW, at 1346-1361 (December 2000). 2011 ETI Rate Case 5-25 Entergy Texas, Inc. Page 24 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 consisted only of salaries and incentive payments linked to operational 2 incentives – would have to be similar to what the total compensation 3 would be if the firm also offered incentive compensation linked to cost 4 control, profitability and stock prices. 5 Second, such a compensation plan would not provide any 6 incentives for employees and managers to control costs. If employees 7 only had incentives to improve non-cash measures of performance, such 8 as safety and reliability, then they would likely over-invest in these 9 measures relative to what customers might prefer, at the expense of 10 alternative, contemporaneous investments that would produce lower costs 11 for customers. 12 Relatedly, a compensation plan consisting of salary and incentives 13 based solely on annual measures of operational performance could likely 14 lead to "horizon problems." By horizon problems, I mean that managers 15 tend to have a natural tendency, absent incentives, to focus on the short 16 run at the expense of the long run. Stock prices by their nature are 17 forward looking. Taken together, a compensation plan that included 18 incentives based on annual measures such as reliability and customer 19 satisfaction, but not incentives based on cost controls, profitability and 20 especially stock prices, could provide incentives for managers to maximize 2011 ETI Rate Case 5-26 Entergy Texas, Inc. Page 25 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 their immediate compensation at the expense of longer-run benefits that 2 the customer could have enjoyed.10 3 For example, consider a manager facing a decision whether to hire 4 additional staff to answer phones in a call center (and bring down phone 5 wait times) or to invest the same amount in a capital investment to put in 6 place a new, more centralized call center that would produce significantly 7 lower costs several years in the future. If the manager is paid purely in 8 cash compensation including an incentive payment based on current-year 9 customer satisfaction surveys (that would include phone wait times), then 10 the manager would be more likely to forgo the long-term investment 11 project and increase payroll by hiring additional employees in order to 12 maximize his or her incentive pay by implementing the short-term solution 13 today. But, at some point, customers are better off by having slightly 14 longer waits on the phone now but reaping the benefits of lower overall 15 costs in the future. A well-designed compensation plan that includes 16 incentives linked to both customer satisfaction (in this example) and cost 17 control, profitability and stock prices would provide incentives for the 18 manager in this example to properly consider the benefits of such a long- 19 term investment without sacrificing current customer satisfaction. 10 See M.P. Narayanan, Form of Compensation and Managerial Decision Horizon, 31 JOURNAL OF FINANCIAL AND QUANTITATIVE ANALYSIS, 4 at 467-491 (1996). 2011 ETI Rate Case 5-27 Entergy Texas, Inc. Page 26 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 Q. IS THERE PUBLISHED EMPIRICAL EVIDENCE THAT SUPPORTS THE 2 OPINION THAT COMPENSATION BASED ON STOCK PRICE COULD 3 CURTAIL SUCH EXCESSIVE SHORT-TERM INVESTMENTS? 4 A. Yes. Empirical evidence exists that some firms hurt their financial 5 performance (stock price) by overinvesting in customer service.11 This 6 result suggests that including stock price in the compensation plan will 7 help ensure against myopic investments in short-term service that would 8 come at the expense of investments that would produce greater long-term 9 benefits to customers. It also points toward the conclusion that basing 10 incentive compensation for purposes of setting rates solely on operational 11 goals could well be harmful to customers' interests in the long run. 12 13 Q. HOW DOES THE INCLUSION OF INCENTIVE COMPENSATION THAT 14 IS LINKED TO COST CONTROLS, PROFITABILITY AND STOCK 15 PRICES HELP AVOID THESE NEGATIVE OUTCOMES FOR 16 CUSTOMERS? 17 A. If a company adds compensation that is linked to cost controls, 18 profitability, and stock prices to a compensation plan that includes base 19 salary and incentives based on non-cash based measures in a reasonable 20 way, customers are likely to be better off. Such incentive compensation 11 Christopher D. Ittner and David F. Larcker, Are Nonfinancial Measures Leading Indicators of Financial Performance? An Analysis of Customer Satisfaction, 36 JOURNAL OF ACCOUNTING RESEARCH, Supplement 1998 at 1 – 35. 2011 ETI Rate Case 5-28 Entergy Texas, Inc. Page 27 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 helps a company attract, motivate, and retain talented employees and 2 gives managers a reason to focus on the long run in addition to the current 3 year's performance, costs, customer service, and the like. 4 This focus on the longer run is evident in the design of ETI's LTIP, 5 stock option and restricted stock plans. For example, ETI's LTIP bases its 6 payments in a particular year on the achievement of goals over the 7 previous three years, encouraging managers to consider consistent and 8 long-term success as key objectives. Plus, options granted vest over a 9 three-year period, forcing managers to think about future years and how 10 the firm will be viewed several years into the future. The stock options 11 also have a life of ten years, which provides an additional incentive to 12 focus on the long term. Such a focus on maximizing stock price over a 13 ten-year period is beneficial for all stakeholders. As stock options may be 14 awarded annually, option grants present a rolling ten-year window for 15 those employees who receive them, reinforcing that long-term view. 16 Similar to stock options, restricted stock is also awarded annually and 17 vests over a three-year period. The fact that the ultimate value realized 18 from restricted stock grants (once they vest) depends on the stock price at 19 that time again provides a focus on maximizing stock price which is likely 20 to be of benefit to all stakeholders for the reasons discussed above. 21 Finally, the provision that requires senior managers to continue to hold 22 stock received via exercising option grants or through the vesting of 23 restricted stock up to a multiple of their salary further encourages longer- 2011 ETI Rate Case 5-29 Entergy Texas, Inc. Page 28 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 run thinking and incentive alignment, as senior managers cannot exercise 2 all their options for cash or cash out their restricted stock positions and be 3 immune to declines in the firm's financial health. 4 5 V. RESPONSE TO COMMON ARGUMENTS AGAINST INCENTIVE 6 COMPENSATION LINKED TO COST CONTROL, PROFITABILITY AND 7 STOCK PRICES FROM THE CUSTOMERS' PERSPECTIVE 8 Q. HOW DO YOU RESPOND TO THE ARGUMENT THAT INCENTIVE 9 COMPENSATION THAT IS LINKED TO COST CONTROL, 10 PROFITABILITY, AND STOCK PRICES WILL BE DETRIMENTAL TO 11 CUSTOMERS BECAUSE IT WILL CAUSE MANAGERS TO CUT 12 CUSTOMER SERVICE-RELATED EXPENSES TO INCREASE 13 PROFITS? 14 A. This argument underscores the importance of a well-balanced 15 compensation plan. By including both incentives based on non-dollar 16 based measures such as customer service, reliability and safety, and 17 incentives based on cost control, profitability and stock price, as does ETI, 18 management will not want to cut one in order to increase the other, but will 19 instead look for balanced decisions that help both. 2011 ETI Rate Case 5-30 Entergy Texas, Inc. Page 29 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 Q. IS THERE EMPIRICAL EVIDENCE THAT THE ADOPTION OF 2 INCENTIVE COMPENSATION WITH TARGETS BASED ON STOCK OR 3 EARNINGS PERFORMANCE BENEFITS CUSTOMERS RATHER THAN 4 HARMS THEM? 5 A. Yes. There is a published study that examines the adoption of long-term 6 incentive plans that reward managers with stock or stock-based 7 compensation, where the stock grants are based on long-run profitability.12 8 The study finds that after the adoption of such plans, managerial 9 compensation is more closely linked to the interests of managers and 10 stakeholders, including customers. This is also consistent with the studies 11 I discuss above in my testimony, such as one that links market value with 12 customer satisfaction. 13 Another published study examines the impact of an incentive plan 14 on the performance of a particular regulated utility.13 This study compared 15 the performance of two divisions within the utility company – one that 16 added an incentive compensation plan with payouts based on financial 17 measures such as sales, costs, and investments, plus employee 18 absenteeism, and a second division that served as a control group 19 because it did not take part in the incentive plan. The authors found for 12 Alka Arora and Pervaiz Alam, CEO Compensation and Stakeholders’ Claims, 22 CONTEMPORARY ACCOUNTING RESEARCH, 3 at 519-547 (Fall 2005). 13 M.M. Petty, Bart Singleton, and David W. Connell, An Experimental Evaluation of an Organizational Incentive Plan in the Electric Utility Industry, 77 JOURNAL OF APPLIED PSYCHOLOGY, 4 at 427-436 (1992). 2011 ETI Rate Case 5-31 Entergy Texas, Inc. Page 30 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 the division that added the incentive plan, performance was significantly 2 better along several dimensions, including operational measures (e.g., 3 reliability) and employee health and safety. This evidence is particularly 4 relevant in that it demonstrates a link between the adoption of an incentive 5 compensation plan with payouts based on financial performance metrics 6 and positive changes in a much broader set of stakeholder measures. 7 8 Q. IS THERE REASON TO BE CONCERNED FROM THE CUSTOMERS' 9 PERSPECTIVE BECAUSE STOCK PRICES AND PROFITS ARE 10 DRIVEN BY MANY OTHER FACTORS IN ADDITION TO COST 11 CONTROLS, OR HAVING A LOW COST OF CAPITAL? 12 A. No. Avoiding this concern is why firms generally do not use compensation 13 plans that consist solely of stock- or profit-based incentive pay – to do so 14 would be too risky for the employees and would lead to larger overall 15 compensation expense because risk-averse individuals would demand 16 higher compensation levels in order to compensate them for bearing the 17 risk of such a hypothetical plan. This is also why stock- and profit-based 18 incentive compensation is more important at the top of the organization. 19 Senior management can more clearly see (and anticipate) the impact of 20 their actions on the firm's stock price, so stock-based compensation is a 21 more efficient compensation tool for this level of management. 2011 ETI Rate Case 5-32 Entergy Texas, Inc. Page 31 of 31 Direct Testimony of Jay C. Hartzell, PhD. 2011 Rate Case 1 VI. CONCLUSION 2 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 3 A. Yes, at this time. 2011 ETI Rate Case 5-33 This page has been intentionally left blank. 2011 ETI Rate Case 5-34 Exhibit JCH-1 2011 TX Rate Case Page 1 of 7 Jay C. Hartzell Department of Finance McCombs School of Business The University of Texas at Austin 1 University Station B6600 Austin, TX 78712 (512) 471-6779; jhartzell@mail.utexas.edu Academic Positions Held McCombs School of Business, The University of Texas at Austin Professor of Finance 2011 to present Chair, Department of Finance 2011 to present Allied Bancshares Centennial Fellow in Finance 2008 to present Executive Director, Real Estate Finance and Investment Center (REFIC) 2007 to present Associate Professor of Finance 2006 to 2011 Associate Director, REFIC 2005 to 2007 Assistant Professor of Finance 2001 to 2006 Stern School of Business, New York University Assistant Professor of Finance 1998 to 2001 Education Ph.D. in Finance, The University of Texas at Austin, 1998 Minors: Real Estate, Economics. B.S. in Business Administration and Economics, Trinity University, 1991 Graduated Cum Laude. National Merit Scholar. Publications “Incentive Compensation and the Likelihood of Termination: Theory and Evidence from Real Estate Organizations” with Greg Hallman and Chris Parsons. 2011. Real Estate Economics 39, 507-546. “Is a Higher Calling Enough? Incentive Compensation in the Church” with Chris Parsons and David Yermack. 2010. Journal of Labor Economics 28, 509-539. “Alternative Benchmarks for Evaluating Mutual Fund Performance” with Tobias M¨ uhlhofer and Sheridan Titman. 2010. Real Estate Economics 38, 121-154. “Explicit vs. Implicit Contracts: Evidence from CEO Employment Agreements” with Stuart Gillan and Robert Parrino. 2009. Journal of Finance 64, 1629-1655. “The Role of Corporate Governance in Initial Public Offerings: Evidence from Real Estate Invest- ment Trusts” with Jarl Kallberg and Crocker Liu. 2008. Journal of Law and Economics 51, 539-562. “Why Do Firms Hold So Much Cash? A Tax-Based Explanation” with Fritz Foley, Sheridan Titman and Garry Twite. 2007. Journal of Financial Economics 86, 579-607 (Lead article). 1 2011 ETI Rate Case 5-35 Exhibit JCH-1 2011 TX Rate Case Page 2 of 7 “The Effect of Corporate Governance on Investment: Evidence from Real Estate Investment Trusts” with Libo Sun and Sheridan Titman. 2006. Real Estate Economics 34, 343-376 (Lead article). Winner of the 2006 Edwin S. Mills Real Estate Economics Best Paper Award. “Active Institutional Shareholders and Costs of Monitoring: Evidence from Executive Compen- sation” with Andres Almazan and Laura T. Starks. 2005. Financial Management 34(4), 5-34 (Lead article). “The Impact of CEO Turnover on Equity Volatility” with Matthew J. Clayton and Joshua Rosen- berg. 2005. Journal of Business 78, 1779-1808. “The Role of the Underlying Real Asset Market in REIT IPOs” with Jarl G. Kallberg and Crocker H. Liu. 2005. Real Estate Economics 33, 27-50. “What’s In It For Me? Private Benefits Obtained by CEOs Whose Companies are Acquired” with Eli Ofek and David Yermack. 2004. Review of Financial Studies 17, 37-61. “Institutional Investors and Executive Compensation” with Laura T. Starks. 2003. Journal of Finance 58, 2351-2374. “Market Reaction to Public Information: The Atypical Case of the Boston Celtics” with Gregory W. Brown. 2001. Journal of Financial Economics 60, 333-370. Research Papers “On the Optimality of Shareholder Control: Evidence from the Dodd-Frank Financial Reform Act” with Jonathan Cohn and Stuart Gillan. “Is There a Disposition Effect in Corporate Investment Decisions? Evidence from Real Estate Investment Trusts” with Alan Crane. “Trade-offs in Corporate Governance: Evidence from Board Structures and Charter Provisions” with Stuart Gillan and Laura Starks. “Institutional Investors as Monitors of Corporate Diversification Decisions: Evidence from Real Estate Investment Trusts” with Libo Sun and Sheridan Titman. Professional and Academic Activities and Service Associate Editor, Review of Financial Studies, 2009-present. Editorial Board, Real Estate Economics, 2007-present. American Real Estate and Urban Economics Association (AREUEA), Board of Direc- tors, 2009-present. Member, 1998-present. Urban Land Institute. Advisory Board (previously known as Executive Committee), Austin District Council, 2010-present. Member, Industrial & Office Park Development Council (Gold), 2009-present. Full member, 2008-present. 2 2011 ETI Rate Case 5-36 Exhibit JCH-1 2011 TX Rate Case Page 3 of 7 National Council of Real Estate Investment Fiduciaries. Data Products Council, 2009. Member, 2008-present. Financial Management Association. Track chair, real estate, annual meeting, 2007. Program committee, European meeting, 2006. Program committee, annual meeting, 2004, 2005. Corporate finance awards committee, annual meeting, 2003. Member, 1998-present. Western Finance Association. Program committee, annual meeting, 2006, 2010, 2011. Member, 1998-present. Conference on Financial Economics and Accounting. Co-organizer, Finance, 19th Annual Meeting, 2008. American Finance Association. Member, 1998-present. Ad Hoc Referee for the following journals: The Accounting Review; American Economic Review; Financial Management; International Jour- nal of Managerial Finance; International Journal of Manpower; International Review of Finance; Journal of Banking and Finance; Journal of Corporate Finance; Journal of Economics, Manage- ment, and Strategy; Journal of Economic Behavior and Organization; Journal of Finance; Journal of Financial and Quantitative Analysis; Journal of Financial Economics; Journal of Financial In- termediation; Journal of Financial Markets, Instruments and Institutions; Journal of Institutional and Theoretical Economics; Journal of Law, Economics, and Organizations; Journal of Real Estate Research; Journal of Risk and Insurance; Journal of Urban Economics; Management Science; Public Finance Review; Quarterly Review of Economics and Finance; Real Estate Economics; Review of Economic Studies; Review of Financial Studies. Service for the University of Texas at Austin Executive Director, Real Estate Finance and Investment Center (REFIC), 2007-present. Associate Director, REFIC, 2005-2007. Member, Finance Department Executive Committee, 2006-present. Member, Graduate Assembly (University wide), 2009-present. Member, Finance Department PhD Committee, 2003-present. Member, University Outstanding Graduate Thesis Award Committee, 2010. Guest speaker, MBA Alumni Network, El Paso, 2010; Seattle and Austin, 2009. Guest speaker, UT LAMP program, 2009. Speaker on Real Estate Valuation, VALCON 2009, Co-sponsored by UT School of Law. Member, Planning Committee, 2009 Mortgage Lending Institute, Sponsored by UT School of Law. Speaker, 2009 Mortgage Lending Institute (Austin and Dallas), Sponsored by UT School of Law. Guest speaker, Austin Bar Association Real Estate Section meeting, 2010. Speaker, 2009 Land Use Conference, Sponsored by UT School of Law. Judge, MBA Finance Tournament, 2001-2006, 2008-2009. Assistant Graduate Advisor and Minority Liaison, Finance Department, 2005-2008. Member, McCombs Option I Policy Committee, 2006-2008. Panel Chair, IC 2 Conference on Corporate Governance in Early-Stage Companies, 2005, 2006. Member, Plus Program Committee, 2003-2005. Judge, MBA Consulting Challenge, 2002, 2003, 2004. Member, MBA Scholarship Committee, 2002. PhD Dissertation Committees UT-Austin: Jennifer Brown (accounting), Alan Crane (co-chair), Ayla Kayhan, Andreas Lawson, Jie Lian, Andras Marosi, Bill Mayew (accounting), Thomas Moeller, Carlos Molina, Saumya Mo- han (co-chair), Chris Parsons (co-chair), Lorenzo Preve, Casey Schwab (accounting), Zekiye Selvili, Nate Sharp (accounting), Stephanie Sikes (accounting), Libo Sun (co-chair), Vahap Uysal, Malcolm 3 2011 ETI Rate Case 5-37 Exhibit JCH-1 2011 TX Rate Case Page 4 of 7 Wardlaw, Peggy Weber (accounting), Li Yong. NYU: Eliezer Fich (economics), Charu Raheja, Jayanthi Sunder. Academic Presentations (includes presentations made by co-authors at major conferences) 2011 Indian School of Business Summer Research Conference, National Bureau of Economic Research (NBER) Program on Law and Economics, Society for Financial Studies Finance Cavalcade, Univer- sity of Michigan. 2010 American Real Estate and Urban Economics Association (AREUEA) annual meeting, Homer Hoyt Institute/Weimer School of Advanced Studies in Real Estate and Land Economics Spring Confer- ence, UC-Irvine Commercial Real Estate Academic Symposium, Indiana University, University of Colorado at Boulder, University of Florida. 2009 AREUEA annual meeting, Association for the Study of Religion Economics and Culture (ASREC) annual meeting, National Bureau of Economic Research (NBER) Economics of Religion conference, Western Finance Association (WFA) annual meeting, National University of Singapore, Ohio State University, Singapore Management University, University of Alabama, University of Cincinnati, Uni- versity of Washington. 2008 AREUEA annual meeting, Real Estate Research Institute (RERI) Conference, McGill University, University of California - Los Angeles. 2007 American Finance Association (AFA) annual meeting, Hong Kong University of Science and Technol- ogy Symposium, Real Estate Research Institute (RERI) Conference, Australian National University, Baylor University, Penn State University, Texas Tech University, University of California - Berkeley, University of Delaware, University of Oklahoma, University of South Florida. 2006 AFA annual meeting (two papers), University of Texas at Dallas. 2005 AREUEA annual meeting, NBER Corporate Governance meeting, Ohio State University, Penn State University, Southern Methodist University, University of North Carolina at Chapel Hill Tax Sym- posium, University of Texas at San Antonio. 2004 Association of Financial Economists (AFE) annual meeting, AREUEA annual meeting, Financial Management Association (FMA) annual meeting, NBER Summer Institute: Corporate Governance Workshop, College of William and Mary. 2003 AFA annual meeting, AREUEA/AFA joint session at annual meeting, University of British Columbia, University of Delaware Corporate Governance Symposium, University of Minnesota, University of North Carolina at Chapel Hill, WFA annual meeting. 2002 Babson College, Oklahoma State University, University of Oklahoma, Real Estate Research Confer- 4 2011 ETI Rate Case 5-38 Exhibit JCH-1 2011 TX Rate Case Page 5 of 7 ence (Vail, CO), University of Southern California. 2001 Arizona State University, University of Oregon. 2000 Dartmouth Center for Corporate Governance/Journal of Financial Economics (JFE) Conference on Contemporary Governance Issues, Marquette University, NYU-Columbia Joint Seminar, South- ern Methodist University, University of Illinois at Urbana-Champaign, University of Texas at Austin. 1999 AFA annual meeting, Harvard Business School/JFE Conference on Complementary Research Method- ologies. 1998 AFA annual meeting, FMA annual meeting, University of Alberta, University of Florida, Georgia State University, University of Michigan Ann Arbor, New York University, University of North Car- olina Chapel Hill, Penn State University, Rice University, Southern Methodist University, Stanford University, and Tulane University. 1997 FMA annual meeting. Other Participation in Academic Conferences Discussant AFA annual meeting, 2002, 2009, 2010. AFA / AFE joint session at annual meeting, 2003. AFE annual meeting, 1999, 2007. AREUEA annual meeting, 1999, 2000, 2004, 2007, 2008. AREUEA mid-year meeting, 2009, 2010. Conference, Financial Economics and Accounting, 1999. Financial Research Association, 2010. FMA annual meeting, 1999, 2002, 2003, 2004, 2006. FMA annual meeting – Tutorial on empirical methodology, 2009. FMA annual meeting – Panel discussion, 2008. Mitsui Symposium at the University of Michigan, 2005. Real Estate Research Institute Conference, 2011. Texas Finance Festival, 2000, 2007. WFA annual meeting, 2001, 2010, 2011. Session Chair AREUEA annual meeting, 2010. AREUEA mid-year meeting, 2009. FMA annual meeting, 2004, 2005. WFA annual meeting, 2006, 2010. Teaching Experience The University of Texas at Austin Current PhD Course: Empirical Corporate Finance. Doctoral course in research methodology and 5 2011 ETI Rate Case 5-39 Exhibit JCH-1 2011 TX Rate Case Page 6 of 7 topics. Current MBA courses: Real Estate Markets. Elective in real estate asset and capital markets. Fi- nancial Management. Core MBA course, Houston MBA program. Current BBA course: Real Estate Finance and Syndication. Elective in real estate capital mar- kets. Previous courses: Financial Management. Core MBA course, also taught in UT’s Executive MBA and Professional MBA programs. Real Estate Analysis. MBA elective in real estate debt markets. Seminar in Real Estate Finance. MBA elective in real estate equity markets. Business Finance. Undergraduate required course. Teaching honors and awards: Twice voted the “Outstanding Core Instructor” by graduating MBA classes. Named to the Honor Roll for teaching for both the MBA and Executive MBA programs. New York University Taught Corporate Finance and Corporate Finance Topics. MBA elective and undergraduate elec- tive, respectively. Honors and Awards Best Paper Award, Indian School of Business Summer Research Conference, 2011. Outstanding Editorial Board Member, Real Estate Economics, 2010. Post Doctoral Award, Weimer School of Advanced Studies in Real Estate and Land Economics, Homer Hoyt Institute, 2010. Real Estate Research Institute (RERI) Grant Recipient (with Alan Crane), 2007. RERI Grant Recipient (with Tobias M¨ uhlhofer and Sheridan Titman), 2006. CBA Foundation Research Excellence Award for Assistant Professors, 2006. (Finance Department nominee, 2003, 2005.) Finance Department nominee for Assistant Professor Teaching Award, 2003, 2004. University Preemptive Fellowship, UT-Austin, 1993-1995. University Continuing Fellowship, UT-Austin, 1995-1997. Austin Mortgage Bankers Association Scholarship, 1995. Lola Wright Foundation Scholarship, 1995-1997. Non-Academic Experience Consulting practice, Austin, Texas. Expert witness and financial consulting. 2007 to present Provided expert witness testimony and served as a consulting expert. Retained as expert witness in multiple cases involving real estate transactions, valuation, contracting issues and market conditions. Experience includes depositions and testimony on multiple occasions. Retained as expert witness for several cases regarding incentive compensation for regulated utilities. Retained as consulting expert by multiple clients for matters involving corporate governance, valuation, and mortgage issues (com- mercial and subprime). Deposed in matter before Superior Court of the State of California (trial pending). Provided (written and oral) testimony and was deposed on behalf of Entergy Louisiana LLC (Docket No. U-20925), 2008. Provided (written and oral) testimony on behalf of Entergy Gulf States, Inc. (Docket No. 34800), 2008. Provided written testimony on behalf of Entergy Arkansas, Inc. (Docket No. 09-084-U), 2009. Provided written testimony on behalf of Entergy Texas, Inc. (Docket No. 37744), 2010. 6 2011 ETI Rate Case 5-40 Exhibit JCH-1 2011 TX Rate Case Page 7 of 7 Hewitt Associates, The Woodlands, Texas. Benefits Consultant. 1991 to 1993 Consulted with clients on administration and ongoing design of defined contribution retirement plans. Earned Certified Employee Benefits Specialist (CEBS) designation. Lola Wright Foundation, Austin, Texas. Investment Performance Consultant. 1995 to 1997 While in graduate school, analyzed performance of foundation’s investment managers. References Furnished upon request. 7 2011 ETI Rate Case 5-41 This page has been intentionally left blank. 2011 ETI Rate Case 5-42 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 ETI 2011 Rate Case ETI EXHIBIT NO. 36 DOCKET NO. 39896 APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION TEXAS, INC. FOR AUTHORITY § TO CHANGE RATES AND § OF TEXAS RECONCILE FUEL COSTS § DIRECT TESTIMONY OF KEVIN G. GARDNER ON BEHALF OF ENTERGY TEXAS, INC. November 2011 2011 ETI Rate Case 8-149 Entergy Texas, Inc. Page 29 of 77 Direct Testimony of Kevin G. Gardner 2011 Rate Case 1 and restricted stock awards to be at market, I conclude that the actual 2 level of stock option and restricted awards for the Test Year is reasonable. 3 4 Q. WHAT CONCLUSION DO YOU DRAW FROM THIS ANALYSIS OF THE 5 ENTERGY COMPANIES’ COMPENSATION VERSUS THE MARKET? 6 A. The Entergy Companies establish compensation targets that reflect the 7 market median for individual components and in the aggregate. The 8 design of the compensation program is reasonable and that design 9 yielded a reasonable combination of base pay, annual incentive 10 compensation, and long-term incentive compensation during the Test 11 Year. 12 13 6. Commission Precedent Regarding Financially Based Incentive 14 Compensation 15 Q. ARE YOU AWARE OF COMMISSION PRECEDENT THAT HAS 16 DISALLOWED FINANCIALLY BASED INCENTIVE COMPENSATION? 17 A. Yes. I have been informed by counsel that what the Commission has 18 termed financially based incentive compensation has been disallowed in 19 several recent rate cases in Texas. 2011 ETI Rate Case 8-181 Entergy Texas, Inc. Page 30 of 77 Direct Testimony of Kevin G. Gardner 2011 Rate Case 1 Q. IS A PORTION OF THE INCENTIVE COMPENSATION REQUESTED BY 2 THE COMPANY IN THIS CASE TIED TO ITS PROFITABILITY AND 3 STOCK PRICE? 4 A. Yes. Based on the methodology used to divide annual incentive pay 5 between financial and operational measures utilized by the utility (and 6 accepted by the Commission Staff) in PUCT Docket Nos. 34800 and 7 37744, approximately 14.1 % of ES l's annual incentive compensation is 8 tied to financial measures such as profitability and stock price. See 9 Exhibit KGG-4. In addition, all of the equity-based long-term incentive 10 compensation programs I describe above are tied to such financial 11 measures. On the other hand, none of the costs of the ML 6 Operational 12 Incentive Plan are tied to financial measures of profitability or stock price. 13 14 Q. IN LIGHT OF THE PRECEDENT YOU DESCRIBE ABOVE, WHY IS ETI 15 REQUESTING RECOVERY OF TEST YEAR COMPENSATION COSTS 16 RELATED TO FINANCIALLY BASED MEASURES? 17 A. Pilst, I a111 infem:ied by crnmsel tba.Ltt:ie-eom~TirCeaent ,.Wii'ig'"" 18 financially based incentives is not required by statute or--~nd that the 19 Commission retains the authority to c~L course. The facts 20 and evidence presented are diff r-El'1lfin each case, and the Commission 21 should continue to c. n 1der whether incentive programs, such as the 22 scribe above, deserve to be divided into its subparts and, in 23 The operational and financial goals of the Entergy 2011 ET! Rate Case 8-182 Entergy Texas, Inc. Page 31of77 Direct Testimony of Kevin G. Gardner 2011 Rate Case 1 Companies' incentive plans are intertwined such that operational 2 measures help the Entergy Companies achieve financial success and the 3 financial measures help the Entergy Companies achieve operational 4 success. 5 Incentive compensation based on financial metrics is a reasonable, 6 necessary, and common component of compensation for companies like 7 the Entergy Companies, including ETI. Such incentive compensation is a 8 part of the compensation programs of substantially all of ETl's peer 9 companies. It is a market necessity that ETI include such pay in its 10 compensation package so that it can hire and retain talented employees, 11 and customers benefit from a utility that offers compensation that attracts 12 and keeps qualified people. 13 Further, Co111pa11y witness Jay C. I la1 tzell ide11tifies-emz·- 14 studies not previously considered by the Commission tha/ nect 15 financially based incentive compensation to benefits for cupefliers. As he 16 testifies, encouraging the financial health of thezom~is in customers' 17 interests because if a company maintains a y cially healthy position, it 18 will tend to have a lower cost of cap~ttfut will in turn benefit customers 19 through lower rates, andzhe fi ar;cially healthy company will be more 20 prepared for emerz ents such as storms. Mr. Hartzell also explains 21 that, withz1nanc·I health, the costs of doing business with suppliers (of 22 both go s and services, including labor) will remain lower because, for 23 20 II ET! Rate Case 8-183 Entergy Texas, Inc. Page 32 of 77 Direct Testimony of Kevin G. Gardner 2011 Rate Case 2 resulting in higher costs that wou -te-hi er rates than would 3 4 Additionally, disallowing financial-based performance targets only 5 serves to encourage utilities to eliminate them, and such an approach 6 weakens the alignment of employees' financial interests with the interest 7 of the ratepayers in having an efficiently run and financially healthy utility. 8 Having only operational targets could encourage utilities to overspend in 9 some areas and would result in an incomplete, unbalanced incentive 10 program that would be atypical when compared with American industry in 11 general and does not create a reasonable mix of incentives. 12 Further, to the extent that the total compensation levels are within 13 market range, it should be at the reasonable discretion of the Entergy 14 Companies to determine how best to pay their employees, and it is 15 common practice for a company to emphasize one form of compensation 16 over another form depending on its circumstances. It would not be 17 appropriate to conclude that, for example, all of the compensation paid to 18 ETI employees is reasonable, so long as it is all paid in the form of base 19 salary, but that it becomes unreasonable when that same level is partially 20 paid out in the form of incentive pay. 21 Finally, the Commission should also reconsider its precedent 22 regarding incentive compensation tied to financial performance because 23 increasing company profitability is a legitimate end for public utilities. 20 II ET! Rate Case 8-184 Entergy Texas, Inc. Page 33 of 77 Direct Testimony of Kevin G. Gardner 2011 Rate Case 1 Investor-owned utilities are authorized by statute to earn a reasonable 2 return on invested capital, and thus trying to achieve financial targets that 3 support the utility’s ability to achieve the authorized return is properly 4 viewed as a legitimate performance goal for a regulated utility. Utilities are 5 allowed and expected to operate at a profit. It is not reasonable to 6 disallow such expenditures as per se unreasonable simply because they 7 are tied to company profitability. 8 9 C. Benefit Plans 10 1. Description of the Entergy Companies’ Benefit Plans 11 Q. PLEASE DESCRIBE THE BENEFIT PLANS PROVIDED BY THE 12 ENTERGY COMPANIES TO THEIR EMPLOYEES. 13 A. The benefit plans consist of: (1) medical and dental plans; (2) employee 14 disability insurance; (3) employee life insurance as well as accidental 15 death and dismemberment insurance; (4) retirement plans, consisting of 16 both a defined benefit pension plan and a 401(k) Savings Plan; and (5) 17 Executive Retirement Benefit Programs. 18 The costs of providing many of these programs are shared between 19 the Entergy Companies and their employees. The cost sharing allows the 20 Entergy Companies to provide competitive benefits programs to 21 employees while maintaining total compensation costs that were 22 comparable with industry medians. 2011 ETI Rate Case 8-185 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 ETI 2011 Rate Case ETI EXHIBIT NO. 41 DOCKET NO. 39896 APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION TEXAS, INC. FOR AUTHORITY § TO CHANGE RATES AND § OF TEXAS RECONCILE FUEL COSTS § DIRECT TESTIMONY OF STEPHANIE B. TUMMINELLO ON BEHALF OF ENTERGY TEXAS, INC. NOVEMBER 2011 2011 ETI Rate Case 9-341 ENTERGY TEXAS, INC. DIRECT TESTIMONY OF STEPHANIE B. TUMMINELLO 2011 RATE CASE TABLE OF CONTENTS Page I. Name and Qualifications 1 II. Introduction 3 III. Background Information Regarding Entergy Corporation and its Subsidiaries 8 IV. Affiliate Transaction Regulation 15 V. Affiliate Case Layout 25 VI. The Affiliate Billing Process 41 VII. ESI Service Billings 44 A. Overview of the ESI Billing Process 44 B. Summary of ESI Billings to Affiliated Companies 55 C. Billing Methods 57 1. Billing Method Overview 57 2. Billing Method Calculations 64 D. Service Company Recipient Allocation (also referred to as Shared Services Loader) 65 E. Payroll Loaders 70 VIII. Other Affiliate Billings 73 IX. Sponsored Classes of Affiliate Costs 74 A. Overview 74 B. Depreciation Class 76 1. Description of Class 76 2011 ETI Rate Case 9-342 2. Necessity 79 3. Reasonableness 81 4. How Costs are Charged 84 C. Service Company Recipient Offsets (also referred to as Shared Services Loader Offsets) 86 1. Description of Class 86 D. Other Expenses Class 87 1. Description of Class 87 2. Necessity 91 3. Reasonableness 92 4. How Costs are Charged 92 X. Sponsored Affiliate Pro Forma Adjustments 93 XI. Benchmarking of ESI COsts 94 XII. Conclusion 98 2011 ETI Rate Case 9-343 EXHIBITS Exhibit SBT-A Affiliate Billings – by Witness, Class and Department Exhibit SBT-A.1 Roadmap to Exhibit SBT-A Exhibit SBT-B Affiliate Billings – by Witness, Class and Project Exhibit SBT-B.1 Roadmap to Exhibit SBT-B Exhibit SBT-C Affiliate Billings – by Witness, Class, Department and Project Exhibit SBT-C.1 Roadmap to Exhibit SBT-C Exhibit SBT-D Affiliate Billings – Pro Forma Summary – by Witness, Class and Pro Forma Exhibit SBT-D.1 Roadmap to Exhibit SBT-D Exhibit SBT-E Project Summaries Exhibit SBT-F Electronic Format of SBT Exhibits and Workpapers on Compact Disc Exhibit SBT-1 Professional Work Experience Exhibit SBT-2 Entergy System Subsidiaries Discussion Exhibit SBT-3 Regulated/Non-Regulated Affiliate Organization Charts Exhibit SBT-4A Service Agreement Between ESI and Entergy Texas, Inc. Exhibit SBT-4B Service Agreement Between ESI and Entergy Arkansas Exhibit SBT-4C Service Agreement Between ESI and EGS Holdings, Inc. Exhibit SBT-4D Service Agreement Between ESI and Entergy Gulf States Louisiana Exhibit SBT-4E Service Agreement Between ESI and Entergy Louisiana Holdings, Inc. Exhibit SBT-4F Service Agreement Between ESI and Entergy Louisiana Exhibit SBT-4G Service Agreement Between ESI and Entergy Louisiana Properties, LLC 2011 ETI Rate Case 9-344 Exhibit SBT-4H Service Agreement Between ESI and Entergy Mississippi Exhibit SBT-4I Service Agreement Between ESI and Entergy New Orleans Exhibit SBT-4J Service Agreement Between ESI and Entergy Corporation Exhibit SBT-4K Service Agreement Between ESI and Entergy Operations Exhibit SBT-4L Service Agreement Between ESI and Entergy Power Exhibit SBT-4M Service Agreement Between ESI and Entergy Enterprises Exhibit SBT-4N Service Agreement Between ESI and System Fuels Exhibit SBT-4O Service Agreement Between ESI and System Energy Exhibit SBT-4P Service Agreement Between ESI and Entergy New Nuclear Utility Development, LLC Exhibit SBT-5 Functions and Classes Exhibit SBT-6 Families and Functions Exhibit SBT-7 Affiliates That Receive Services from ESI Exhibit SBT-8 ESI Test Year Per Book Billings to Affiliates by Project Exhibit SBT-9 ESI Annual Billings to Affiliates 2008 – 2010 Exhibit SBT-10A FERC Order Accepting Entergy’s Service Company Cost Allocation Request Exhibit SBT-10B FERC Order Accepting ESI’s October 28, 2010 Filing Request Exhibit SBT-11 Affiliate Billing Exclusions by Class Exhibit SBT-12 Pro Forma Documentation List Exhibit SBT-13 Flow of Test Year Affiliate Costs – G-6 Schedules and Supporting Information Exhibit SBT-14 Elements of ETI’s Cost of Service Exhibit SBT-15 Affiliate Billing Process Discussion 2011 ETI Rate Case 9-345 Exhibit SBT-16 ESI Time and Expense Training Exhibit SBT-17 Direct vs. Allocated ESI Test Year Per Book Billings to Affiliates Exhibit SBT-18 Definition of Terms – Direct, Indirect, Allocated, and Overhead Exhibit SBT-19 ESI Billing Methods – Basis for Calculation and Types of Costs Allocated Using Billing Methods Exhibit SBT-20 Entergy Arkansas Test Year Billings to Affiliates Exhibit SBT-21 Entergy Gulf States Louisiana Test Year Billings to Affiliates Exhibit SBT-22 Entergy Louisiana Test Year Billings to Affiliates Exhibit SBT-23 Entergy Mississippi Test Year Billings to Affiliates Exhibit SBT-24 Entergy New Orleans Test Year Billings to Affiliates Exhibit SBT-25 Entergy Non-Regulated Affiliates Test Year Billings to Regulated Affiliates Exhibit SBT-26 ESI Net Book Value of Assets Exhibit SBT-27 Service Company Property Per Employee with Graph Exhibit SBT-28A ESI Benchmarking Analysis Peer Group Exhibit SBT-28B Service Company O&M as a Percentage of Total Company O&M Exhibit SBT-28C Service Company O&M as a Percentage of Total Company Revenue Exhibit SBT-28D Service Company O&M as a Percentage of Total Company Assets Exhibit SBT-28E Service Company O&M Per Service Company Employee 2011 ETI Rate Case 9-346 Entergy Texas, Inc. Page 1 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 I. NAME AND QUALIFICATIONS 2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 3 A. My name is Stephanie B. Tumminello. During the Commission’s last 4 review in Docket No. 37744 and during the test period in this case through 5 June 24, 2011, my name was Stephanie B. Neyland. My business 6 address is 639 Loyola Avenue, New Orleans, LA 70113. 7 8 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY? 9 A. I am employed by Entergy Services, Inc. (“ESI” or “Entergy Services”) as 10 Manager of Affiliate Accounting and Allocations, which was formerly 11 Intrasystem Affiliate Billing (“ISABill”).1 12 13 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? 14 A. I am testifying on behalf of Entergy Texas, Inc. ("ETI" or the “Company"). 15 16 Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND. 17 A. I have a Bachelor of Science degree in Accounting from the University of 18 New Orleans. I am a Certified Public Accountant licensed in the State of 19 Louisiana. 1 This is distinct from the intra-system bill invoicing process discussed by Company witness Patrick J. Cicio. 2011 ETI Rate Case 9-347 Entergy Texas, Inc. Page 2 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE BRIEFLY DESCRIBE YOUR PROFESSIONAL EXPERIENCE. 2 A. I have been employed by ESI for approximately 15 years and have held 3 various positions in the Accounting and Finance organizations. ESI is one 4 of the service companies providing services to Entergy Corporation and its 5 subsidiaries.2 My work experience is described in more detail in 6 Exhibit SBT-1. 7 8 Q. WHAT ARE THE PRINCIPAL AREAS OF YOUR RESPONSIBILITY AS 9 MANAGER OF AFFILIATE ACCOUNTING AND ALLOCATIONS? 10 A. I am responsible for the intrasystem affiliate billing processes of the 11 Entergy Service Companies: ESI, Entergy Operations, Inc. (“EOI”), 12 Entergy Enterprises, Inc. (“EEI”), and Entergy Nuclear Operations, Inc. 13 (“ENUC”). I oversee these companies’ billing processes and procedures 14 to ensure they are in compliance with applicable requirements of the retail 15 regulators of the Entergy Operating Companies,3 the Public Utility Holding 16 Company Act of 2005 (“PUHCA 2005”), and Federal Energy Regulatory 17 Commission (“FERC”) regulations.4 2 Each of these subsidiaries is a separate legal entity. 3 I use the name “Entergy” or “Entergy Companies” to mean, collectively, Entergy Corporation and its direct and indirect subsidiaries. Each of these subsidiaries is a separate legal entity. The Entergy Operating Companies (“Operating Companies”) are: ETI; Entergy Arkansas, Inc. (“EAI” or “Entergy Arkansas”); Entergy Gulf States Louisiana, L.L.C. (“EGSL,” “EGSLA,” or “Entergy Gulf States Louisiana”); Entergy Louisiana, LLC (“ELL” or “Entergy Louisiana”); Entergy Mississippi, Inc. (“EMI” or “Entergy Mississippi”); and Entergy New Orleans, Inc. (“ENOI” or “Entergy New Orleans”). 4 See Exhibit SBT-2 for a discussion of the regulation of Entergy Corporation’s subsidiaries. 2011 ETI Rate Case 9-348 Entergy Texas, Inc. Page 3 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 My responsibilities also include billings, allocations, approval of 2 billing method assignments on project codes, and updating and 3 maintaining processes for allocations related to the affiliates. I have 4 overall responsibility for all affiliate billing functions. 5 My responsibilities include oversight for the review of the elements 6 of billable project code (“PC”) requests and the approval of each billable 7 PC. I am also responsible for analyzing the amounts billed to affiliates to 8 ensure that the billing process is efficient and effective. In addition, I have 9 oversight for the provision of advice and training for ESI employees 10 regarding affiliate billing issues. My accounting responsibility for ESI as a 11 business unit (“BU”; also known as “legal entity” or “LE”) includes 12 providing information required for the preparation of the ESI FERC Form 13 60, Annual Report of Centralized Service Companies, as well as the 14 FERC Form 60 reports for EOI, EEI and ENUC. 15 16 II. INTRODUCTION 17 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 18 A. The primary purpose of my testimony is to provide an overview of ETI’s 19 affiliate case. I also discuss the regulation of affiliate transactions. In 20 addition, I explain how the affiliate portion of the Company’s filing is 21 organized. I address several affiliate transaction-related issues, such as 22 the affiliate billing processes used by ESI, the Operating Companies, other 2011 ETI Rate Case 9-349 Entergy Texas, Inc. Page 4 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 regulated affiliates,5 and non-regulated affiliates to collect and bill costs to 2 their affiliates, including ETI, for services rendered. A more detailed 3 discussion of the purpose of my testimony is provided below. 4 Affiliate Case Layout: In the Affiliate Case Layout section of my 5 testimony, I describe how affiliate charges to ETI have been organized 6 into classes, explain how the affiliate case is organized and how it ties to 7 the G-6 schedules and supporting workpapers,6 and introduce the other 8 affiliate witnesses. I describe how the information in this filing is presented 9 for the purpose of showing: 10 affiliate costs charged to ETI are necessary; 11 affiliate costs charged to ETI are reasonable; 12 the prices charged to ETI for each class of items are no 13 higher than the prices charged to other affiliates, or to 14 non-affiliates, for the same or similar class of items; and 15 the allocated amounts represent the actual cost of services 16 to ETI. 17 I also explain why the affiliate costs charged to ETI do not include 18 prohibited expenses and that the services provided to ETI by affiliates are 19 not duplicative of services provided internally by ETI or other affiliates. 20 Each affiliate cost witness will provide testimony supporting the 21 reasonableness and necessity of the specific affiliate classes that he or 5 Entergy’s regulated affiliates include the Operating Companies as well as System Fuels, Inc. (“SFI” or “System Fuels”); EOI; ESI; System Energy Resources, Inc. (“SERI” or “System Energy”); and Entergy New Nuclear Utility Development, LLC. 6 Schedule G-6 is a section within the Public Utility Commission of Texas’ (“Commission’s”) Rate Filing Package (“RFP”). It includes a summary of test year affiliate transactions. 2011 ETI Rate Case 9-350 Entergy Texas, Inc. Page 5 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 she sponsors. These affiliate witnesses will also support the 2 appropriateness of the billing methods that are used for the classes that 3 they address. Exhibits that show, in consistent formats, the affiliate 4 expenses for each class accompany each witness’s testimony. As the 5 affiliate overview witness, my testimony collects and assembles all of 6 those individual class exhibits into one exhibit for ease of review. 7 Affiliate Transaction-Related Issues: In connection with my 8 discussion of the affiliate billing processes, I will: 9 (a) provide background information regarding Entergy 10 Corporation and its regulated and non-regulated 11 subsidiaries; 12 (b) describe the affiliate billing process, including 13 discussions regarding project billings, loaned 14 resource billings, co-owner billings, and controls; 15 (c) discuss the ESI service billings, including an overview 16 of the billing process, a summary of ESI charges to 17 affiliated companies, the service company recipient 18 allocation process, billing methods, and allocation 19 rates and statistics; 20 (d) discuss billings to ETI during the test year; and 21 (e) describe the pro forma adjustments associated with 22 the affiliate billings to ETI included in this filing and 23 discuss those pro forma adjustments that I sponsor. 24 In addition to the overview of affiliates charges, I sponsor three specific 25 classes of affiliate costs: (1) Depreciation (which pertains to depreciation 26 and amortization of ESI assets used in providing services); (2) Service 27 Company Recipient Offsets (sometimes referred to as “Shared Services 28 Loader Offsets”); and (3) Other Expenses. 2011 ETI Rate Case 9-351 Entergy Texas, Inc. Page 6 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. WHAT EXHIBITS ARE YOU INCLUDING AS PART OF YOUR 2 TESTIMONY? 3 A. The exhibits that I am including as part of my testimony appear in the list 4 following the Table of Contents. Because these exhibits are voluminous 5 and include a number of spreadsheets, I have provided all of my exhibits, 6 workpapers, and schedule information on the attached CD, labeled 7 Exhibit SBT-F, rather than in paper form. 8 9 Q. DO YOU SPONSOR OR CO-SPONSOR ANY SCHEDULES IN THE 10 RATE FILING PACKAGE? 11 A. Yes, I co-sponsor several Rate Filing Package (“RFP”) schedules filed in 12 this proceeding. I am co-sponsoring with other witnesses the following 13 schedules: 14 Schedule G-6 15 Schedule G-6.1 16 Schedule G-6.2 17 I am also co-sponsoring the following workpapers included in 18 support of Schedule G-6 of the RFP: 19 G-6 WPs G-6.1 WPs G-6.2 WPs 20 WP/G-6 (set 1) WP/G-6.1 (set 1) WP/G-6.2 (set 1) 21 WP/G-6 (set 2) WP/G-6.1 (set 2) WP/G-6.2 (set 2) 22 WP/G-6 (set 3) WP/G-6.1 (set 3) WP/G-6.2 (set 3) 23 WP/G-6 (set 4) WP/G-6.1 (set 4) WP/G-6.2 (set 4) 2011 ETI Rate Case 9-352 Entergy Texas, Inc. Page 7 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 WP/G-6 (set 5) WP/G-6.1 (set 5) WP/G-6.2 (set 5) 2 WP/G-6 (set 6) WP/G-6.1 (set 6) WP/G-6.2 (set 6) 3 These schedules and supporting workpapers were prepared by me 4 or under my direct supervision. 5 6 Q. ON WHAT BASIS WERE THE SCHEDULES THAT YOU JUST 7 MENTIONED PREPARED? 8 A. They were prepared from the books and records of ESI and its affiliates 9 and are accurate summaries of the business records on which they are 10 based. Deloitte & Touche LLP (“D&T”), the independent auditor for 11 Entergy Corporation and subsidiaries, has performed a review of the 12 historical financial information included in Schedules A through W 13 (excluding L and R) of the RFP, and have reported its findings in 14 Schedule S. 15 16 Q. WHAT TEST YEAR IS ETI USING IN THIS FILING? 17 A. The test year in this case is the twelve months ended June 30, 2011. 18 19 Q. WHAT IS THE DOLLAR AMOUNT OF AFFILIATE CHARGES THAT ETI 20 HAS INCLUDED IN THE TEST YEAR COST OF SERVICE? 21 A. RFP Schedule G-6 shows that the Company’s “Total ETI Adjusted” 22 amount for affiliate charges for the test year is $78,998,777. 2011 ETI Rate Case 9-353 Entergy Texas, Inc. Page 8 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Additionally, there are capitalized affiliate charges included in the 2 ETI capital additions that the Company is seeking to place in rate base. 3 These capital additions are addressed by other witnesses. ESI costs are 4 directly charged or allocated to capital work orders in the same manner as 5 costs are allocated to operations and maintenance expense-based project 6 codes, the latter of which are discussed in detail in my testimony. 7 8 Q. WHAT TYPE OF SYSTEM DO THE ENTERGY COMPANIES USE TO 9 CAPTURE COSTS? 10 A. The Entergy Companies use a project costing application (PowerPlant) 11 that provides a single point of entry for all PCs (that is, “project codes”). A 12 PC is an alpha numeric code that is assigned to individual projects 13 established within organizations (also referred to as “departments”). Each 14 PC is applicable to a specific assignment or activity. For example, a PC 15 would be assigned to a project to develop a specific software application, 16 a specific construction project, an employee training project, or any of a 17 myriad of activities that are necessary to run a utility. 18 19 III. BACKGROUND INFORMATION REGARDING ENTERGY 20 CORPORATION AND ITS SUBSIDIARIES 21 Q. PLEASE BRIEFLY DESCRIBE ENTERGY CORPORATION. 22 A. Entergy Corporation owns both regulated and non-regulated companies. 23 Exhibit SBT-2 provides a detailed discussion of Entergy Corporation 2011 ETI Rate Case 9-354 Entergy Texas, Inc. Page 9 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 subsidiaries. Exhibit SBT-3 is an organization chart for Entergy 2 Corporation and its subsidiaries, including both regulated and direct non- 3 regulated companies, as of June 30, 2011. 4 5 Q. PLEASE BRIEFLY DESCRIBE ENTERGY CORPORATION AND ITS 6 WHOLLY-OWNED REGULATED SUBSIDIARIES. 7 A. Entergy Corporation owns all of the outstanding common stock of six retail 8 Operating Company subsidiaries: ETI, EAI, EGSL, ELL, EMI, and ENOI. 9 As of June 30, 2011, these Operating Companies provided electric service 10 to approximately 2.7 million customers in the states of Arkansas, 11 Louisiana, Mississippi, and Texas. 12 Entergy Corporation also owns all of the outstanding common stock 13 of System Energy, ESI, and EOI, which are regulated by the Nuclear 14 Regulatory Commission (“NRC”) and/or the FERC. System Energy is a 15 nuclear generating company that sells the generating capacity and energy 16 from its 90% interest in the Grand Gulf nuclear plant at wholesale to its 17 only customers: EAI, ELL, EMI, and ENOI. ESI is a service company 18 established to provide professional services primarily to Entergy’s 19 regulated utilities or Operating Companies. 20 EOI is also a service company, and was established to provide 21 nuclear management and operations and maintenance services to 22 Entergy’s regulated nuclear plants: Arkansas Nuclear One; River Bend; 2011 ETI Rate Case 9-355 Entergy Texas, Inc. Page 10 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Waterford 3; and Grand Gulf. Although these plants are operated by EOI, 2 they are owned by: EAI; EGSL; ELL; and System Energy, respectively. 3 4 Q. PLEASE PROVIDE AN OVERVIEW OF ENTERGY’S NON-REGULATED 5 SUBSIDIARIES. 6 A. Entergy’s non-regulated subsidiaries include, among others, EEI, Entergy 7 Power, LLC (“EPL”), a wholesale power producer that is a subsidiary of 8 Entergy Asset Management, Inc., and ENUC, a service company 9 established to provide nuclear management and operations services to 10 Entergy’s non-regulated nuclear plants. For a more detailed discussion of 11 Entergy’s direct non-regulated affiliates, please refer to Exhibit SBT-2. 12 13 Q. FROM WHICH OF THE ENTERGY SUBSIDIARIES DOES ETI RECEIVE 14 THE MOST SIGNIFICANT LEVEL OF AFFILIATE CHARGES? 15 A. ETI receives the most significant level of affiliate charges from ESI. In 16 addition to affiliate charges from ESI, ETI receives charges from the other 17 Operating Companies, EOI, and from certain non-regulated affiliates. 18 19 Q. WHY IS ESI THE SOURCE OF MOST OF ETI’S AFFILIATE CHARGES? 20 A. Centralization of activities through the creation of service companies 21 results in economies of scale and provides a pool of centralized expertise 22 for Entergy Corporation’s regulated utility affiliates. As noted previously, 23 ESI, EOI, EEI, and ENUC are the four primary service companies. EOI 2011 ETI Rate Case 9-356 Entergy Texas, Inc. Page 11 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 provides services to the regulated nuclear plants, and EEI and ENUC 2 provide services to non-regulated affiliates, as more fully described in 3 Exhibit SBT-2. I provide an overview of the services provided by ESI. 4 5 Q. PLEASE DESCRIBE THE PURPOSE AND FUNCTION OF ESI. 6 A. ESI is authorized to conduct business as a service company by a 7 temporary order issued by the Securities and Exchange Commission 8 (“SEC”) in March 1963, which was made permanent in March 1965. ESI 9 was formed as, and continues to be, primarily a service company for the 10 Operating Companies. Costs incurred by ESI to provide services to all 11 regulated companies, including ETI, are billed at cost and do not produce 12 a profit. ESI also performs services for some of Entergy’s non-regulated 13 companies through ESI’s Service Agreement with EEI. These services 14 are billed at cost plus 5%. Exhibit SBT-2 provides a more detailed 15 discussion of ESI’s purpose and function. 16 17 Q. WHAT TYPES OF SERVICES DOES ESI PROVIDE? 18 A. The services ESI provides to its affiliates include general executive, 19 management, advisory, administrative, human resources, accounting, 20 legal, regulatory, and engineering services. These services are provided 21 in accordance with Service Agreements entered into by ESI and the 22 respective affiliates to which it provides services. The Service 23 Agreements between ESI and its affiliates are included as Exhibits SBT- 2011 ETI Rate Case 9-357 Entergy Texas, Inc. Page 12 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 4A through SBT-4P. These Service Agreements outline the general types 2 of services that ESI provides. 3 ESI provides services according to functional groupings that reflect 4 the way ESI is organized. See Exhibits SBT-5 and SBT-6 for details, 5 which I discuss in more detail later in my testimony. These groupings are 6 reflected in the presentation of ETI’s affiliate expenses in this filing and 7 represent a compilation of the services that are provided to ETI by ESI. 8 The types of services outlined in the Service Agreements between 9 ESI and the affiliates that it serves have been grouped in classes that are 10 discussed later in my testimony for the purpose of presentation in this 11 filing. Exhibit SBT-7 shows the affiliates that receive services from ESI. 12 13 Q. IS THE SERVICE AGREEMENT BETWEEN ESI AND ETI DIFFERENT 14 IN SUBSTANCE FROM THE SERVICE AGREEMENTS ESI HAS WITH 15 THE OTHER AFFILIATED COMPANIES? 16 A. No. The Service Agreements between ESI and each of the other Entergy 17 affiliates discussed previously are the same in substance. However, the 18 types and amounts of services vary among the companies. 19 20 Q. ARE ALL NON-REGULATED ENTERGY COMPANIES PARTIES TO 21 SERVICE AGREEMENTS WITH ESI? 22 A. No. ESI does not directly provide services to all of the non-regulated 23 affiliates. ESI, however, does provide services directly to EPL and EEI, 2011 ETI Rate Case 9-358 Entergy Texas, Inc. Page 13 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 and has service agreements with these two non-regulated companies. 2 When ESI provides services to EEI, the provision of these services is 3 often the result of a request for services made by a non-regulated 4 company to EEI. When that situation arises, the billing for that service is 5 made by ESI to EEI and, in turn, EEI bills the non-regulated company for 6 the service. As shown on Exhibit SBT-8, total ESI billings to EPL and EEI 7 were .03% and 16.06%, respectively, of ESI’s total billings to all affiliates 8 during the test year.7 As indicated in Exhibit SBT-9, total ESI billings to 9 EPL declined from 2008 to 2010, while billings to EEI increased from 2008 10 to 2010. 11 12 Q. WHAT TYPES OF SERVICES ARE PROVIDED BY ESI TO THE NON- 13 REGULATED AFFILIATES THROUGH EEI? 14 A. Although ESI was formed to serve primarily Entergy Corporation’s 15 regulated utility operations, there are three general categories of services 16 that ESI provides to the non-regulated companies through EEI. The first 17 type of services provided by ESI through EEI are those provided solely to 18 EEI or a non-regulated affiliate. For instance, ESI provides services with 19 regard to specific non-routine projects, tax issues, legal issues, or 20 accounting issues directly associated with EEI or a non-regulated affiliate. 21 These costs are billed 100% to EEI. 7 Exhibit SBT-8 includes a schedule of ESI billings to affiliates during the test year. 2011 ETI Rate Case 9-359 Entergy Texas, Inc. Page 14 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 The second type of services provided by ESI through EEI is the 2 type of services that concurrently are used by both the regulated and 3 non-regulated Entergy affiliates. For example, non-regulated companies 4 participate in certain payroll, human resources, benefits, accounts 5 payable, communications, and support services primarily provided to the 6 regulated companies. However, the level of such services may differ 7 between the regulated and non-regulated affiliates. For example, ESI 8 processes all of the payroll transactions for the regulated affiliates, 9 whereas ESI processes some, but not all, of the non-regulated companies’ 10 payroll transactions. In this instance, the billing method for allocating the 11 costs assigned to the associated PC is calculated based on the number of 12 paychecks issued for those companies for which the services are 13 provided. 14 The third type of ESI service provided and billed to EEI is for EEI’s 15 allocable share of ESI’s overhead and departmental costs. ESI, like any 16 corporation, incurs costs that are necessary to maintain and support its 17 existence. Therefore, ESI’s expenses for its own overhead costs, such as 18 accounting, tax, legal, and other support, must be distributed reasonably 19 to all of the legal entities that ESI serves, including EEI. 20 Further, each department (also referred to as “organization”) within 21 ESI must incur costs that are not related to any specific service, but which 22 are costs that are attributable to a department. EEI is billed for a portion 23 of these costs. These include items such as administrative labor costs 2011 ETI Rate Case 9-360 Entergy Texas, Inc. Page 15 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 associated with office and general service employees (including not only 2 salaries and wages but also other related employment costs), rent and 3 utilities, depreciation, materials and supplies, telephone use, and postage. 4 5 Q. DOES ESI PROVIDE ANY SERVICES TO THE REGULATED OR NON- 6 REGULATED COMPANIES FREE OF CHARGE OR AT A DISCOUNT? 7 A. No. ESI costs incurred to provide services to its regulated affiliates are 8 billed at cost and to non-regulated affiliates at cost plus 5% (in accordance 9 with a June 1999 SEC order). 10 11 IV. AFFILIATE TRANSACTION REGULATION 12 Q. ARE YOU FAMILIAR WITH THE STANDARDS USED BY THE PUBLIC 13 UTILITY COMMISSION OF TEXAS (“COMMISSION”) TO DETERMINE 14 THE REASONABLENESS OF EXPENSES ASSOCIATED WITH 15 AFFILIATE TRANSACTIONS AND THE ELIGIBILITY OF SUCH 16 EXPENSES FOR INCLUSION IN COST OF SERVICE? 17 A. Yes. I am not an attorney, but part of my job responsibility is to be familiar 18 with the legal standards (rules, statutes, and court cases) governing 19 affiliate transactions and cost recovery in Commission proceedings. 20 Section 36.058 of the Public Utility Regulatory Act (“PURA”) and Railroad 2011 ETI Rate Case 9-361 Entergy Texas, Inc. Page 16 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Commission of Texas v. Rio Grande Valley Gas Company8 set forth the 2 affiliate standard applicable to Commission rate proceedings. This 3 standard involves a four-part inquiry that addresses: (1) the necessity of 4 the affiliate services on a class of items basis; (2) the reasonableness of 5 the costs related to the class; (3) the compliance with the “no higher than” 6 standard, which requires that the price for the same or similar services 7 provided be no higher for one affiliate or non-affiliated person than for 8 another affiliate or non-affiliated person;9 and (4) whether the price 9 charged reasonably approximates (or represents) the actual cost of the 10 services. I also explain that the price charged excludes costs that may not 11 be allowed for ratemaking purposes, and that charges are not duplicated. 12 13 Q. ARE YOU FAMILIAR WITH THE REQUIREMENTS OF SUB-SECTION (f) 14 OF PURA SECTION 36.058? 15 A. Yes. It is my understanding that if the Commission determines that the 16 requested amount of an affiliate expense during the test period is 17 unreasonable, then, instead of disallowing the entire affiliate expense, the 18 Commission must determine the reasonable level of the affiliate expense 19 and include that reasonable level in the utility’s cost of service. 8 683 S.W.2d 783 (Tex. App.-Austin 1984 no writ). 9 ESI does not provide services to non-affiliated entities. 2011 ETI Rate Case 9-362 Entergy Texas, Inc. Page 17 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. DOES THE COMMISSION’S RFP APPLICABLE TO ETI PROVIDE ANY 2 GUIDANCE REGARDING HOW TO DEMONSTRATE THE 3 REASONABLENESS AND NECESSITY OF AFFILIATE CHARGES? 4 A. No. ETI is required to use, and is using for this case, the Electric Utility 5 Rate Filing Package for Generating Utilities (Sept. 9, 1992). This is the 6 RFP for fully-bundled electric utilities such as ETI. Section V of the 7 Commission’s RFP for unbundled transmission and distribution utilities,10 8 however, provides a set of “guiding principles” with illustrative types of 9 evidence that may be used to support the affiliate charges, including 10 historical cost trends, process improvements, benchmarking, outsourcing, 11 third-party reviews, operating statistics, and other metrics. These guiding 12 principles are not, strictly speaking, applicable to this case because ETI is 13 not an “unbundled” transmission and distribution utility. Nonetheless, 14 each Company affiliate cost witness has relied upon these guiding 15 principles to marshal the evidence to support his or her affiliate costs. 16 17 Q. HOW DO THE AFFILIATE COSTS INCLUDED IN THE COMPANY’S 18 REVENUE REQUIREMENT COMPLY WITH APPLICABLE STANDARDS 19 IN TEXAS STATUTES AND RULES? 20 A. Each affiliate cost witness sponsors testimony supporting his or her 21 specific affiliate classes. Their testimony, in conjunction with my 10 Investor Owned Utility Transmission & Distribution Cost of Service Rate Filing Package (April 2, 2003). 2011 ETI Rate Case 9-363 Entergy Texas, Inc. Page 18 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 testimony, demonstrates that the affiliate costs meet the standards I 2 describe above for recovery of affiliate charges. Also, Company witness 3 Jeanne J. Kenney presents additional support by demonstrating the 4 reasonableness of ETI’s costs from an overall benchmarking perspective. 5 Other witnesses support the reasonableness of categories of costs, such 6 as compensation and benefits (by ETI witness Kevin G. Gardner) and the 7 supplies and acquisition processes (by ETI witness Joseph M. Hunter). 8 9 Q. WHAT OTHER REGULATORY REQUIREMENTS REGARDING 10 AFFILIATE TRANSACTIONS ARE RELEVANT TO A REVIEW OF 11 AFFILIATE TRANSACTIONS? 12 A. I am advised that prior to February 8, 2006, Entergy Corporation was a 13 holding company registered under the Public Utility Holding Company Act 14 of 1935 (“PUHCA 1935”) and, therefore, was subject to the oversight of 15 the SEC. ESI, which is a service company established in accordance with 16 PUHCA 1935, was subject to regulation by the SEC. Effective February 8, 17 2006, however, pursuant to the Energy Policy Act of 2005 (“EPAct 2005”), 18 PUHCA 1935 was repealed and the Public Utility Holding Company Act of 19 2005 (“PUHCA 2005”) was enacted. Section 1275(b) of EPAct 2005 20 provides that: 21 In the case of non-power goods or administrative or 22 management services provided by an associate company 23 organized specifically for the purpose of providing such 24 goods or services to any public utility in the same holding 25 company system, at the election of the system or a State 2011 ETI Rate Case 9-364 Entergy Texas, Inc. Page 19 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 commission having jurisdiction over the public utility, the 2 [FERC], after the effective date of this subtitle, shall review 3 and authorize the allocation of the costs for such goods or 4 services to the extent relevant to that associate company. 5 6 Q. WHAT REGULATIONS HAS FERC ISSUED RELATED TO SERVICE 7 COMPANIES TO REPLACE THE SEC REGULATIONS? 8 A. On December 8, 2005, the FERC issued Order No. 667, which added Part 9 366 to its regulations to implement the repeal of PUHCA 1935 and the 10 enactment of PUHCA 2005. Under the definitions provided in the PUHCA 11 2005 regulations, ESI is a “service company” in that it was organized 12 specifically for the purpose of providing non-power goods or services to a 13 “public utility” within the same holding company system. Each of the 14 Operating Companies is a “public utility” as defined in the PUHCA 2005 15 regulations. The PUHCA 2005 regulations also include Section 366.5, 16 which essentially mirrors the language of Section 1275(b) of the EPAct 17 2005, and adds that “[s]uch election to have the [FERC] review and 18 authorize cost allocations shall remain in effect until further [FERC] order.” 19 On October 19, 2006, the FERC issued Order No. 684, “Financial 20 Accounting, Reporting and Records Retention Requirements under the 21 Public Utility Holding Company Act of 2005.” This order establishes 22 regulations for service companies related to the Uniform System of 23 Accounts (“USofA”), the filing of the FERC Form 60, and records 24 retention requirements. 2011 ETI Rate Case 9-365 Entergy Texas, Inc. Page 20 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 On February 21, 2008, the FERC issued Order No. 707, 2 “Cross-Subsidization Restrictions on Affiliate Transactions.” This order 3 codified, among other things, the FERC requirements for the pricing of 4 non-power goods and services provided by a service company and 5 between other affiliates. On July 17, 2008, the FERC issued Order No. 6 707-A, “Order on Rehearing.” This order granted rehearing and 7 clarification, in part, of Order No. 707. 8 9 Q. WHAT ARE THE FERC REQUIREMENTS FOR THE PRICING OF NON- 10 POWER GOODS AND SERVICES PROVIDED BY A SERVICE 11 COMPANY? 12 A. FERC Order Nos. 667 and 667-A allowed traditional, centralized service 13 companies that previously used the SEC’s “at cost” standard for the 14 pricing of sales of non-fuel, non-power goods and services to 15 FERC-jurisdictional utilities to continue to use that “at cost” standard (the 16 “at cost” standard means, as I understand it, that cost of the services does 17 not include a component of profit.) Further, in its Order Nos. 667 and 667- 18 A, the FERC indicated that “at cost” pricing of non-power goods and 19 services provided by traditional, centralized service companies such as 20 ESI to associate public utilities is presumed to be reasonable. 21 Specifically, in Order No. 667 the FERC stated: 22 Fundamentally, we agree…that centralized provision of 23 accounting, human resources, legal, tax and other such 24 services benefits ratepayers through increased efficiency 2011 ETI Rate Case 9-366 Entergy Texas, Inc. Page 21 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 and economies of scale. Further we recognize that it is 2 frequently difficult to define the market value of the 3 specialized services provided by centralized service 4 companies. Accordingly, the Commission will apply a 5 rebuttable presumption that costs incurred under “at cost” 6 pricing of such services are reasonable. 7 FERC Order Nos. 707 and 707-A prohibit, among other things, a 8 franchised public utility with “captive customers” from receiving non-power 9 goods and services from a centralized service company at a price above 10 cost. This “at cost” pricing requirement for service company billings is 11 consistent with previous FERC and SEC requirements. ESI is in 12 compliance with the pricing requirements of FERC Order Nos. 707 and 13 707-A. ESI’s compliance with the FERC’s “at cost” requirement helps to 14 ensure that ESI affiliate costs charged to ETI are reasonable. 15 16 Q. DID THE ENTERGY COMPANIES REQUEST A REVIEW OF COST 17 ALLOCATIONS BY FERC FOLLOWING THE ENACTMENT OF PUHCA 18 2005? 19 A. Yes. On October 13, 2006, ESI, on behalf of the Operating Companies, 20 submitted a filing to the FERC requesting that FERC: (a) review and 21 accept the cost allocation methods included in the service agreements 22 used for the sale of non-power goods and services by ESI and EOI to the 23 Operating Companies; and (b) accept the existing service agreements 24 effective as of February 8, 2006. The filing was made pursuant to Section 25 1275(b) of the EPAct 2005, Section 205 of the Federal Power Act, and 2011 ETI Rate Case 9-367 Entergy Texas, Inc. Page 22 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Section 366.5(a) and Part 35 of the FERC’s regulations (18 C.F.R.). In 2 electing to make this filing, ESI sought a determination by the FERC with 3 respect to the appropriate allocation and pricing of services provided by 4 ESI and EOI to the Operating Companies. 5 6 Q. DID THE FERC ISSUE AN ORDER IN CONNECTION WITH THE 7 ENTERGY COMPANIES’ FILING IN THIS MATTER? 8 A. Yes. On December 12, 2006, the FERC issued an order accepting the 9 service agreements and proposed methods of cost allocation effective 10 February 8, 2006, as requested in the Entergy Companies’ filing. In that 11 order, the FERC agreed that Section 1275(b) of EPAct 2005 was intended 12 to vest authority in a federal regulator to help avoid disparate regulatory 13 treatments with respect to service company cost allocations. The FERC 14 order accepting ESI’s and EOI’s service company cost allocation request 15 is included as Exhibit SBT-10A. 16 17 Q. DOES PUHCA 2005 CONTAIN ANY PROCEDURES FOR CHANGING 18 COST ALLOCATIONS REVIEWED AND ACCEPTED BY THE FERC? 19 A. No. PUHCA 2005 does not separately specify procedures for changing 20 cost allocations reviewed and accepted by the FERC. However, in its 21 December 12, 2006 order discussed above, the FERC explained that any 22 changes to a FERC-filed rate, including the cost allocation provisions, 2011 ETI Rate Case 9-368 Entergy Texas, Inc. Page 23 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 must be made in accordance with Section 205 and 206 of the Federal 2 Power Act. 3 4 Q. HAVE THERE BEEN ANY MODIFICATIONS TO THE ENTERGY 5 COMPANIES’ COST ALLOCATION FORMULAS DURING THE TEST 6 YEAR? 7 A. Yes. On October 28, 2010, ESI, on behalf of the Operating Companies, 8 submitted a filing to the FERC requesting that FERC review and accept a 9 proposed new cost allocation formula based on the historical usage of 10 servers, platforms, and mainframes. On December 20, 2010, the FERC 11 issued an order accepting ESI’s October 28, 2010 cost allocation request. 12 The FERC order accepting ESI’s cost allocation request is included as 13 Exhibit SBT-10B. 14 15 Q. DOES THE FERC EXERCISE ANY ADDITIONAL OVERSIGHT 16 AUTHORITY OVER ENTERGY’S SERVICE COMPANIES? 17 A. Yes. The FERC, in its oversight role, is authorized to conduct periodic 18 audits of service company transactions. The FERC also requires that 19 centralized service companies file an annual report on FERC Form 60. 2011 ETI Rate Case 9-369 Entergy Texas, Inc. Page 24 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. HAS THE FERC CONDUCTED ANY AUDITS OF ENTERGY 2 CORPORATION’S SERVICE COMPANIES? 3 A. Yes. As noted above, the FERC, under the authority of the Public Utility 4 Holding Company Act of 2005, is authorized to periodically conduct audits 5 of service companies. These service company audits include an 6 examination of each service companies’ compliance with 7 cross-subsidization restrictions on affiliate transactions at 18 C.F.R. Part 8 35, accounting, recordkeeping, and reporting requirements at 18 C.F.R. 9 Part 366, compliance with the Uniform System of Accounts (“USofA”) for 10 centralized service companies at 18 C.F.R. Part 367, and preservation of 11 records requirements for service companies at 18 C.F.R. Part 368. During 12 the most recent FERC audit of Entergy Corporation’s four service 13 companies, including ESI, covering the period January 2006 through 14 December 2008, the FERC tested for compliance with the aforementioned 15 regulations by conducting tests of the service companies’ cost allocations 16 and the charges billed by the service companies. The FERC reviewed 17 and tested the supporting details for the service companies’ cost allocation 18 methodologies, tested the centralized service companies’ costs and 19 accounting, and reviewed selected service companies’ billings and the 20 corresponding associated franchised public utilities’ accounting for the 21 billings. The FERC letter order dated December 9, 2009 in connection 22 with this audit found there were no significant deficiencies related to the 2011 ETI Rate Case 9-370 Entergy Texas, Inc. Page 25 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 allocation methodologies, accounting, or pricing of service 2 company transactions.11 3 4 V. AFFILIATE CASE LAYOUT 5 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY? 6 A. This section of my testimony provides an overview of how the Company’s 7 affiliate transaction case is organized to meet the affiliate standard in 8 Texas, including: an explanation of why the case is organized in this 9 manner; an explanation of how the testimony and exhibits of each of the 10 affiliate witnesses link to G-6 Schedules; and an explanation of how the 11 testimony, exhibits and G-6 Schedules relate to the PCs that I describe in 12 more detail later in my testimony. 13 14 Q. HOW DO THE AFFILIATE COSTS PRESENTED IN THIS CASE RELATE 15 TO THE RATES THE COMPANY SEEKS TO ESTABLISH IN THIS 16 CASE? 17 A. The Company’s cost of providing services includes both costs incurred 18 directly by the Company and affiliate charges. As discussed earlier, the 19 Commission determines the eligibility of affiliate costs for recovery in rates 20 based on the standards required by law. The Company has presented its 21 affiliate information in a manner that will permit the Commission to review 11 Workpaper WP/SBT-1 includes the FERC letter order dated December 9, 2009. 2011 ETI Rate Case 9-371 Entergy Texas, Inc. Page 26 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 its affiliate costs for compliance with the affiliate standard. The affiliate 2 costs are a component of the rates the Company is requesting to 3 implement in this docket. 4 5 Q. PLEASE DESCRIBE THE COMPANY’S ORGANIZATION OF ITS 6 AFFILIATE CASE. 7 A. The Company’s affiliate case is organized to correspond to the way in 8 which ETI and ESI are organized and managed. ESI’s business is divided 9 into two basic functional groupings or “families.” These families are (1) 10 Corporate Support, and (2) Operations. 11 12 Q. ARE THE TWO FAMILIES FURTHER BROKEN DOWN INTO SMALLER 13 GROUPINGS? 14 A. Yes. Within each of these families, we have more discrete functions or 15 service categories. Thus, for example, as shown in Exhibit SBT-6, entitled 16 “Families and Functions,” the “Operations” family (shorthand for Utility 17 Operations Group) is comprised of traditional utility functions such as 18 Generation, Transmission, Distribution, and Customer Service. 2011 ETI Rate Case 9-372 Entergy Texas, Inc. Page 27 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. ARE THESE “FUNCTIONS” THE “CLASSES” THAT THE COMPANY 2 HAS IDENTIFIED FOR PURPOSES OF MEETING THE AFFILIATE 3 STANDARD IN PURA, WHICH REQUIRES COSTS TO BE ORGANIZED 4 ON AN ITEM OR CLASS OF ITEMS BASIS? 5 A. Not necessarily. In some cases, there is only one class within a function. 6 But the functions are not always the classes the Company proposes for 7 purposes of proving its compliance with the affiliate standard set forth in 8 PURA. The Company determined that some of these functions may be 9 too broad for purposes of meeting the affiliate standard and may not 10 permit the detailed review of affiliate transactions envisioned by the 11 Commission. Further, the Company wanted to ensure that the witnesses 12 who explain the affiliate services provided to ETI have the requisite degree 13 of accountability and technical knowledge to provide sufficient detailed 14 information concerning each class of services (that is “class of items”) that 15 they sponsor. 16 17 Q. HOW DID THE COMPANY SEPARATE THESE FUNCTIONS INTO 18 CLASSES OF SERVICES FOR PURPOSES OF PROVING 19 COMPLIANCE WITH THE AFFILIATE STANDARD? 20 A. The Company and ESI focused on the way they organize and operate 21 their businesses in order to identify classes of services for purposes of 22 meeting the affiliate standard. Thus, the Company looked at the various 23 departments that compose each function and grouped these departments 2011 ETI Rate Case 9-373 Entergy Texas, Inc. Page 28 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 into classes based on factors such as the extent to which the departments 2 provided interrelated services or had some other logical connection to 3 each other. For example, departments such as accounts payable and 4 cash operations, payroll, fixed asset operations, revenue operations, 5 external reporting, and Affiliate Accounting and Allocations were included 6 in the Financial Services Class of services. A similar process was 7 followed for identifying classes within each of the functions shown on 8 Exhibit SBT-5. Additionally, some cost items were grouped based on 9 resource code instead of department code12 (examples of these include 10 depreciation and income taxes) and based on physical location for Nelson 11 6 co-owner costs. 12 13 Q. HOW MANY CLASSES OF AFFILIATE CHARGES ARE THERE IN THE 14 COMPANY’S CASE, AND WHO SPONSORS THEM? 15 A. Affiliate services provided to ETI are grouped into 25 classes of items in 16 the Company’s filing. Exhibit SBT-5 shows the functions composing each 17 family as well as the classes that make up each function. For example, 18 Exhibit SBT-5 shows that there are six functions within the Corporate 19 Support family. Below each function are the classes that compose that 20 function and the name of the witness who sponsors that affiliate class of 12 A resource code indicates the type of costs used or consumed in the conduct of work activities, while a department code indicates which organization provides the services (and budgets, captures and reports on the related costs for those services). 2011 ETI Rate Case 9-374 Entergy Texas, Inc. Page 29 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 services. This exhibit also shows the Total ETI Adjusted amount for each 2 class of affiliate services. For example, the Financial Services class, 3 which is sponsored by Company witness Donna S. Doucet, is in the 4 Finance function. This exhibit does not include the level of test year 5 affiliate charges for capital additions. 6 7 Q. WHAT INFORMATION DOES EACH WITNESS PROVIDE WITH 8 RESPECT TO THE CLASSES OF SERVICES THAT HE OR SHE 9 SPONSORS? 10 A. Although the testimony of each of the affiliate witnesses varies depending 11 on subject matter, there are certain common elements that I will explain. 12 Each witness who sponsors a class of services describes why those 13 services are necessary; explains why the costs of those services are 14 reasonable; discusses the billing methods used to ensure that prices paid 15 by ETI are no higher than the prices paid by other Entergy affiliates for the 16 same or similar services; and also explains that the costs paid by ETI 17 represent the actual costs of the services provided. In addition, each 18 affiliate witness has included as exhibits to his or her testimony a 19 schematic that highlights by family and function the class or classes that 20 he or she is supporting, i.e., an exhibit identical to my Exhibits SBT-5 and 21 SBT-6. 2011 ETI Rate Case 9-375 Entergy Texas, Inc. Page 30 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. ARE THERE ANY OTHER EXHIBITS THAT ARE COMMON TO ALL 2 AFFILIATE WITNESSES? 3 A. Yes. Each affiliate witness sponsors key affiliate cost-related exhibits that 4 are designated by letters (i.e., A, B, C, D) instead of numbers. For ease of 5 reference, I will refer to them as Exhibits A, B, C, and D. For example, the 6 affiliate cost exhibits supporting Company witness Doucet’s testimony are 7 labeled Exhibits DSD-A, DSD-B, DSD-C, and DSD-D. These exhibits 8 present the cost of affiliate services in various levels of detail for each 9 class of services included in Schedule G-6 of the Company’s Application. 10 For each class of services sponsored by the witness, Exhibits A, B and C 11 include all affiliate billings that originate at ESI, billings to ETI from the 12 other Operating Companies (EAI, EGSL, ELL, EMI, or ENOI), and billings 13 to ETI from other affiliates. In addition, Exhibit D contains information 14 about test year pro forma adjustments, if any, affecting each class of 15 services sponsored by the witness. For the convenience of the parties, I 16 have included my Exhibits SBT-A, SBT-B, SBT-C, and SBT-D, which are 17 compilations of all witnesses’ Exhibits A, B, C, and D, respectively. My 18 Exhibit SBT-D differs slightly from the witnesses’ Exhibit D in that it 19 includes FERC accounts.13 13 Workpaper WP/SBT-2 provides, among other things, FERC account information for pro forma adjustments included on Exhibit SBT-D. 2011 ETI Rate Case 9-376 Entergy Texas, Inc. Page 31 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE DESCRIBE THE INFORMATION THAT IS CONTAINED IN 2 EXHIBIT A. 3 A. Exhibit A is entitled, “Affiliate Billings – by Witness, Class and 4 Department.” Exhibit A shows for each class of services sponsored by 5 that witness the amounts by department for the test year. The information 6 presented in Exhibit A permits the reviewer to examine which departments 7 had charges within each class of services and the amounts of test year 8 costs for each department within the class. 9 10 Q. PLEASE SUMMARIZE HOW TO CALCULATE THE TEST YEAR 11 AMOUNT FOR EACH CLASS OF SERVICES DESCRIBED IN EXHIBIT A 12 OF EACH WITNESS’ TESTIMONY. 13 A. To calculate the test year amount for a class of service described in 14 Exhibit A, the reviewer need only add Column “E” (ETI Per Books) + 15 Column “F” (Exclusions) + Column “G” (Pro Forma Amount) to arrive at 16 the Total ETI Adjusted amount shown in Column “H,” which is the amount, 17 by billing entity, included in the G-6 workpapers for this class of services. 18 19 Q. HAVE YOU PREPARED AN EXHIBIT THAT SUMMARIZES THE 20 CONTENTS OF COLUMN “F” (EXCLUSIONS) IN EXHIBITS A, B, C, 21 AND D? 22 A. Yes. Exhibit SBT-11, entitled “Affiliate Billing Exclusions by Class,” shows 23 by function and by class all exclusions from ETI’s test year affiliate 2011 ETI Rate Case 9-377 Entergy Texas, Inc. Page 32 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 expenses for the Corporate Support family and the Operations family. As 2 shown in this exhibit, test year exclusions totaled approximately 3 $17.7 million. Exclusions include amounts charged to FERC USofA 4 capital accounts (FERC accounts 107 to 118); other balance sheet 5 accounts (FERC accounts 152 to 242); and below the line accounts 6 (FERC accounts 408202 to 426500). With the exception of amounts 7 charged to certain capital accounts, these exclusions are made in order to 8 arrive at a total cost amount that does not include costs that may not be 9 recovered in rates, such as expenses prohibited from being included in 10 rates by Texas law. Amounts included in the exclusions category do not 11 represent pro forma adjustments. 12 13 Q. HAVE YOU PREPARED AN EXHIBIT TO ASSIST THE REVIEWER IN 14 TRACKING THE DATA PRESENTED IN EXHIBIT A? 15 A. Yes. I have prepared Exhibit SBT-A.1 for that purpose. This “roadmap” 16 exhibit illustrates in a brief and easily understandable way, what specific 17 information is provided in each column of Exhibit A. 18 19 Q. PLEASE DESCRIBE EXHIBIT B THAT IS ATTACHED TO EACH 20 WITNESS’ S TESTIMONY. 21 A. Exhibit B is entitled, “Affiliate Billings – by Witness, Class and Project.” 22 Exhibit B shows for each class of services sponsored by that witness the 23 amounts by project code (also referred to as a “PC”) for the test year. The 2011 ETI Rate Case 9-378 Entergy Texas, Inc. Page 33 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 information presented in Exhibit B permits the reviewer to examine the 2 following: which PCs were charged within each class of services; which 3 billing method was used; and the amounts included in test year costs for 4 each PC within the class. From here, the reviewer can, in turn, refer to the 5 Project Summaries included as Exhibit SBT-E for additional detail 6 concerning each PC included in each class within the Company’s filing. I 7 discuss the information presented in the Project Summaries in greater 8 detail later in my testimony. 9 10 Q. PLEASE DESCRIBE EXHIBIT C. 11 A. Exhibit C, which is entitled “Affiliate Billings – by Witness, Class, 12 Department and Project,” is a combination of Exhibits A and B. This 13 additional sort of the data, by department and project, allows the reviewer 14 to determine which department charged a particular PC for the particular 15 services. For example, Company witness Doucet’s Exhibit DSD-C allows 16 the reviewer to trace a total of $26,678 Total ETI Adjusted test year 17 amount, including pro forma adjustments, to the Financial Services Class 18 billings to project code “F3PPF72700.” Exhibit DSD-C further shows that 19 these services were performed by the following billing departments: 20 FA256, FA259, FA26A, FN2F1, and RA2IA.14 14 Workpaper WP/SBT-3 provides the department descriptions for each department code. 2011 ETI Rate Case 9-379 Entergy Texas, Inc. Page 34 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE DESCRIBE EXHIBIT D. 2 A. Exhibit D, entitled “Affiliate Billings – Pro Forma Summary – by Witness, 3 Class and Pro Forma,” contains information about test year pro forma 4 adjustments affecting the class or classes that a particular Company 5 witness sponsors. The witnesses’ Exhibit D contains a brief description of 6 the nature of the pro forma adjustment, assigns the adjustment an 7 identifying number, shows the billing entity of the transaction, shows which 8 witness supports the pro forma, and presents the amount of the pro forma 9 that is included in the “Total” column of Schedule G-6.2. In addition to the 10 items described above, Exhibit SBT-D also contains the FERC account for 11 each pro-forma adjustment. 12 13 Q. HAVE YOU PREPARED ANY DOCUMENTS REGARDING THE PRO 14 FORMA ADJUSTMENTS INCLUDED IN EXHIBIT SBT-D? 15 A. Yes. Exhibit SBT-12 includes summary information regarding each pro 16 forma adjustment included in Schedule G-6.2. This Exhibit includes the 17 pro forma number, title, description, ETI pro forma amount, and supporting 18 witness. The main purpose of this exhibit is to accumulate in one place all 19 originating affiliate pro forma adjustments to the test year, and to provide 20 additional supporting detail for why the pro forma was made. 21 Also, workpapers WP/SBT-2a through WP/SBT-2s include 22 calculations for each pro forma adjustment. WP/SBT-2 is an index to the 2011 ETI Rate Case 9-380 Entergy Texas, Inc. Page 35 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 calculations included to assist the reviewer in locating the calculation for 2 any pro forma adjustment listed in Schedule G-6.2. 3 4 Q. HAVE YOU PREPARED ANY ADDITIONAL DOCUMENTS THAT WILL 5 ASSIST REVIEWERS IN UNDERSTANDING THE INFORMATION 6 CONTAINED IN EACH COLUMN OF EXHIBITS B THROUGH D? 7 A. Yes. Although the Company believes that the level of detail that it has 8 provided in this filing is more than sufficient to enable the Commission to 9 evaluate the Company’s affiliate costs, the Company recognizes that it 10 may be difficult for a reviewer to recall the type of information that is 11 provided in each column of each of these exhibits. For this reason, I have 12 included in my testimony as Exhibits SBT-B.1, SBT-C.1, and SBT-D.1 13 “roadmaps” that show what question is answered by each column in each 14 exhibit, similar to “roadmap” Exhibit SBT-A.1 that I described earlier. 15 16 Q. ARE YOU SPONSORING ALL COSTS CONTAINED IN EXHIBITS 17 SBT-A, SBT-B, SBT-C, AND SBT-D? 18 A. No. My Exhibits SBT-A, SBT-B, SBT-C, and SBT-D are an aggregation of 19 all the Exhibits A, B, C, and D for each affiliate witness in the Company’s 20 case. Although the affiliate witnesses have attached their Exhibits A, B, C, 21 and D to their direct testimony, it may be more convenient for the reviewer 22 to have a single copy of all these exhibits in one place to facilitate review 23 of the Company’s filing. I am a co-sponsor of these exhibits because 2011 ETI Rate Case 9-381 Entergy Texas, Inc. Page 36 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 these cost exhibits include the classes of costs I sponsor (that is, the 2 Depreciation, Service Company Recipient Offsets, and the Other 3 Expenses classes), the exclusions and pro forma adjustments (some of 4 which I sponsor) to the test year affiliate charges for all classes of costs, 5 and the application of the cost allocation methods to the PCs. 6 7 Q. HAVE YOU PREPARED ADDITIONAL WORKPAPERS SUPPORTING 8 EACH OF THE G-6 SCHEDULES? 9 A. Yes. I have prepared six different sorts of the G-6 schedules, which are in 10 addition to the required FERC account presentation contained in 11 Schedules G-6, G-6.1 and G-6.2. The Company is providing this 12 information in its direct filing in this case to facilitate an efficient, timely 13 review of the Company’s affiliate case. 14 15 Q. HAS THE COMPANY MADE THIS INFORMATION AVAILABLE IN 16 ELECTRONIC FORM? 17 A. Yes. As I explained above, Exhibit SBT-F is a compact disc that includes 18 this information. The Company has invoked Microsoft Excel’s “Auto Filter” 19 command in the spreadsheet files to help users find information quickly. 2011 ETI Rate Case 9-382 Entergy Texas, Inc. Page 37 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE DESCRIBE THE VARIOUS WORKPAPERS THAT THE 2 COMPANY HAS PREPARED IN CONNECTION WITH ITS SCHEDULES 3 G-6, G-6.1, AND G-6.2. 4 A. There are six variations of Schedules G-6, G-6.1, and G-6.2 included in 5 the workpapers to the G-6 schedules. They are: 6 1) Affiliate billings by billing entity to ETI by billing method and 7 project code (WP/G-6 (set 1); WP/G-6.1 (set 1); and WP/G- 8 6.2 (set 1)); 9 2) Affiliate billings by billing entity to ETI by FERC account and 10 class (WP/G-6 (set 2); WP/G-6.1 (set 2); and WP/G-6.2 (set 11 2)); 12 3) Affiliate billings by billing entity to ETI by class, project code, 13 and billing method (WP/G-6 (set 3); WP/G-6.1 (set 3); and 14 WP/G-6.2 (set 3)); 15 4) Affiliate billings by billing entity to ETI by class, by FERC 16 account, project code, and billing method (WP/G-6 (set 4); 17 WP/G-6.1 (set 4); and WP/G-6.2 (set 4)); 18 5) Affiliate billings by billing entity to ETI by FERC account, 19 project code, and billing method (WP/G-6 (set 5); WP/G-6.1 20 (set 5); and WP/G-6.2 (set 5)); and 21 6) Affiliate billings by billing entity to ETI by project code, billing 22 method, and FERC account (WP/G-6 (set 6); WP/G-6.1 (set 23 6); and WP/G-6.2 (set 6)). 24 25 Q. WHAT IS THE RELATIONSHIP BETWEEN EXHIBITS A, B, C, AND D 26 AND THE COMPANY’S G-6 SCHEDULES? 27 A. The G-6 schedules present the Company’s request for all affiliate billings, 28 for the test year, by FERC account and billing entity, as follows: 29 1) Schedule G-6 – Total ETI Adjusted amount of affiliate 30 billings, 2011 ETI Rate Case 9-383 Entergy Texas, Inc. Page 38 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 2) Schedule G-6.1 – total per books affiliate billings (after 2 exclusions), and 3 3) Schedule G-6.2 – pro forma adjustments to affiliate billings. 4 The Commission’s RFP requires the G-6 schedules to be 5 presented by FERC account. 6 Exhibits A, B, and C present the same amounts that are in the 7 Schedules G-6, G-6.1, and G-6.2, but in various sorts of detail within each 8 class arranged in a way so that the witnesses can further show that the 9 costs meet the Commission’s affiliate standards. As stated previously, the 10 Company has sorted the amounts by department, by project code, and by 11 both department and project code in Exhibits A, B, and C, respectively. 12 Exhibit D presents for each class of services additional detail on the pro 13 forma adjustments included in Schedule G-6.2. With the use of the 14 workpaper set WP/G-6 (set 4), the reviewer can follow amounts in Exhibits 15 A through D through to the G-6 schedules, which are presented in the 16 required FERC account format. Thus, for example, the reviewer can trace 17 cost data related to a particular class to a FERC account, to a project 18 code, and to a billing method by referring to WP/G-6 (set 4). Similarly, if a 19 reviewer desired to determine what other types of projects or activities 20 were billed utilizing a particular billing method shown in a Company 21 witness’s Exhibit C, the reviewer need only turn to WP/G-6 (set 1) in order 22 to ascertain this information. I have prepared a chart illustrating how the 23 affiliate cost information fits together (see Exhibit SBT-13). 2011 ETI Rate Case 9-384 Entergy Texas, Inc. Page 39 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE EXPLAIN HOW ONE WOULD GET FROM YOUR COST 2 EXHIBITS TO THE G-6 SCHEDULES. 3 A. Note that the same process I will describe below can be used for any of 4 the Exhibits A through C. I will use as an example my Depreciation 5 Affiliate Class, which can be found on Exhibit SBT-A. To trace the data 6 into the G-6 schedules, one would first need to obtain the subtotals of the 7 class by billing entity. The subtotal in Column H (Total ETI Adjusted) of 8 $1,777,986 for billing entity ESI agrees with the workpaper set WP/G-6 9 (set 4), which is sorted by billing entity, class, FERC account, project 10 code, and billing method. The Depreciation Class is billed to various 11 FERC accounts, as seen on WP/G-6 (set 4). Each of these FERC 12 account totals for the Depreciation Class can be traced into workpaper set 13 WP/G-6 (set 2), which is sorted by billing entity, FERC account and then 14 by class. On WP/G-6 (set 2), each FERC account is subtotaled. 15 16 Q. HOW COULD A REVIEWER OBTAIN MORE DETAILED INFORMATION 17 ABOUT A PARTICULAR PROJECT CODE? 18 A. For each project code, a reviewer could “drill down” to a very detailed level 19 of information contained in the Project Summaries included in my Exhibit 20 SBT-E. The Project Summaries, which are supported by all witnesses of 21 classes that charged to a particular project code, are arranged in project 22 code order and are indexed by page number. 2011 ETI Rate Case 9-385 Entergy Texas, Inc. Page 40 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. WHAT INFORMATION IS INCLUDED IN EACH PROJECT SUMMARY? 2 A. Each Project Summary shows the following information for each project 3 code: 4 test year billings to ETI by FERC account; 5 test year billings to ETI by class of services; 6 a statement of the purpose of the project code; 7 the primary activities encompassed by the project code; 8 the products or deliverables resulting from the project code; 9 and 10 the billing method associated with the project code and a 11 justification for that billing method. 12 13 Q. HOW ELSE CAN THE PROJECT SUMMARIES BE USED AS A TOOL 14 FOR REVIEWING AFFILIATE DATA? 15 A. The Project Summaries can be used to trace project code data from the 16 Exhibits B and C into the G-6 Schedules. For example, Financial Services 17 Class costs related to Project Code F3PPF72700, entitled “Cognos 18 Reporting Support,” can be found on Exhibit SBT-B. The Total ETI 19 Adjusted amount for the Financial Services Class for this project is 20 $26,678 for the test year. From Exhibit B, one can obtain a good deal of 21 information about the services provided – billing method, project 22 description, Total ETI Adjusted amount, etc. For example, Billing Method 23 GENLEDAL is applied to Project Code F3PPF72700. If more detail is 24 required to verify why Billing Method GENLEDAL is appropriate, or which 2011 ETI Rate Case 9-386 Entergy Texas, Inc. Page 41 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 other classes may have charged this project, or the types of activities 2 being provided, one could go to the index of Project Summaries included 3 with Exhibit SBT-E and locate the page number for the Project Summary 4 for Project Code F3PPF72700 (page 961 of Exhibit SBT-E). The FERC 5 account amounts for this PC can be traced into workpaper set 5 - billings 6 by FERC account, project code, and billing method (WP/G-6 (set 5), 7 WP/G-6.1 (set 5), and WP/G-6.2 (set 5)). On WP/G-6 (set 5), each FERC 8 account is subtotaled by billing entity, and this subtotal will agree to 9 Schedule G-6 for that FERC account. 10 11 VI. THE AFFILIATE BILLING PROCESS 12 Q. PLEASE DESCRIBE THE AFFILIATE TRANSACTIONS THAT 13 PRIMARILY AFFECT ETI’S COST OF SERVICE IN THIS APPLICATION. 14 A. Two categories of affiliate costs affected ETI’s cost of service for the test 15 year: 16 the cost of the services ESI provides that are directly billed 17 or allocated to ETI; and 18 charges from other Operating Companies and from ETI’s 19 other affiliates that are directly billed to ETI for services 20 rendered. 21 Exhibit SBT-14 depicts the relationship between affiliate costs and 22 ETI’s cost of service. To understand these categories of affiliate 23 transactions, it is important to understand the affiliate billing process. 2011 ETI Rate Case 9-387 Entergy Texas, Inc. Page 42 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE DESCRIBE THE PROCESS USED BY THE ENTERGY 2 COMPANIES TO CHARGE AFFILIATES FOR SERVICES PROVIDED. 3 A. ESI and the other Entergy-affiliated companies use three mechanisms to 4 bill affiliates for services rendered: (1) project billings; (2) loaned resource 5 billings; and (3) co-owner billings. These mechanisms are included in the 6 affiliate billing process (“billing process”). Project billings are transactions 7 billed to affiliates for services rendered using PCs to determine how costs 8 should be billed to affiliates. Loaned resource billings are transactions 9 that bill charges directly to the Department and/or Business Unit that is the 10 recipient of the services provided. Loaned resource billings include 11 charges for the payroll applicable to “loaned” employees (for example line 12 crews from one Operating Company sent to assist another Operating 13 Company in storm restoration), transportation, and materials and supplies. 14 Co-owner billings include costs incurred by one affiliate for the operation 15 and maintenance of a jointly-owned plant, and subsequently transferred to 16 another affiliate based on their ownership. During the test year, EGSL 17 transferred costs to ETI related to the jointly-owned Nelson 6 plant using 18 the co-owner billing process. The co-owner billing process and the Nelson 19 6 billings are discussed more fully in the Direct Testimony of Company 20 witness Winfred W. Garrison. Service companies such as ESI typically bill 21 via project billings. Other affiliates can only use loaned resource billings 22 or co-owner billings when billing or transferring costs to an affiliate. 2011 ETI Rate Case 9-388 Entergy Texas, Inc. Page 43 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE SUMMARIZE THE CONTROLS THAT HAVE BEEN 2 ESTABLISHED TO HELP ENSURE THAT BILLINGS TO AFFILIATES 3 PROPERLY REFLECT THE ACTUAL COST OF AN ITEM OR SERVICE. 4 A. There are several controls in place to help ensure that billings to affiliates 5 represent the actual costs of items or services provided to such affiliates. 6 These process controls include: 7 Multiple Approvals of PCs 8 Approval of Loaned Resource Billing Transactions 9 Co-owner Allocation Rules 10 Approval of Source Documentation 11 Budget Process Activities 12 Monthly Allocation Results and Billing Analysis 13 Authorization Required to Access Corporate Applications 14 Billing Analysis Review Team (“BART”) Monthly Reviews of 15 ESI Billings 16 Employee Training 17 Internal Reviews of Affiliate Transactions and Processes 18 External Reviews and Audits of Affiliate Transactions and 19 Processes 20 Sarbanes-Oxley Controls and Testing 21 FERC Compliance Controls and Testing 22 Affiliate Transactions Policy 23 Each of the controls is an integral part of a multi-faceted process 24 that is designed to bill the appropriate share of reasonable and necessary 2011 ETI Rate Case 9-389 Entergy Texas, Inc. Page 44 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 costs to the Operating Companies. A more detailed description of these 2 billing controls is included in Attachment 8 to my Exhibit SBT-15. Exhibit 3 SBT-15 is an exhibit that explains a number of different aspects of the ESI 4 billing process. 5 6 VII. ESI SERVICE BILLINGS 7 A. Overview of the ESI Billing Process 8 Q. PLEASE PROVIDE A BRIEF EXPLANATION OF YOUR EXHIBIT 9 SBT-15: “AFFILIATE BILLING PROCESS DISCUSSION.” 10 A. As I discussed earlier, ESI and the other Entergy-affiliated companies use 11 three mechanisms to bill affiliates for services rendered: (1) project 12 billings; (2) loaned resource billings; and (3) co-owner billings. These 13 mechanisms are included in the affiliate billing process, which is discussed 14 in detail in my Exhibit SBT-15, “Affiliate Billing Process Discussion.” For 15 further clarification, I have included nine attachments to Exhibit SBT-15: 16 1) SBT-15 Attachment 1 – Comparison of Affiliate Billing 17 Mechanisms Overview; 18 2) SBT-15 Attachment 2 – Affiliate Billings by Billing Type; 19 3) SBT-15 Attachment 3 – Project Code Set-Up and Use 20 Flowchart; 21 4) SBT-15 Attachment 4 – Guidelines for Completing a Project 22 Scope Statement; 23 5) SBT-15 Attachment 5 – The Service Company Billing 24 Process Flowchart; 25 6) SBT-15 Attachment 6 – ESI Billing Method Tables; 2011 ETI Rate Case 9-390 Entergy Texas, Inc. Page 45 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 7) SBT-15 Attachment 7 –Billing Method Summary; 2 8) SBT-15 Attachment 8 – Affiliate Billing Process Controls; 3 and 4 9) SBT-15 Attachment 9 – Deloitte & Touche, LLP’s 2010 5 Independent Accountant’s Report on Applying Agreed-Upon 6 Procedures (dated June 23, 2011). 7 8 Q. PLEASE DESCRIBE THE ESI BILLING PROCESS. 9 A. As shown in Attachment 2 to Exhibit SBT-15, the vast majority of ESI’s 10 billings to ETI are project billings. In order to bill an affiliate for services 11 provided via a project billing, a transaction must have an assigned PC. 12 Each PC is assigned a single billing method that determines how costs 13 captured under the PC will be distributed. The billing method results in 14 either a “direct” billing (billed 100% to one affiliate) or an “allocation” to 15 multiple affiliates. When services are provided to multiple affiliates, 16 charges for services rendered by ESI are allocated using billing methods 17 based on FERC-accepted formulae. 18 19 Q. WHEN IS THE PROJECT CODE ASSIGNED TO A TRANSACTION? 20 A. The PC is assigned at the time the transaction is entered into a source 21 system (e.g., Time Entry System, Accounts Payable). The employee 22 submitting the charge is most familiar with the charge, and is responsible 23 for applying the correct PC to the transaction. In addition, the employee’s 2011 ETI Rate Case 9-391 Entergy Texas, Inc. Page 46 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 budget coordinator may assist in determining the correct PC for a 2 specific cost. 3 In addition, several allocations, such as payroll and other loaders, 4 will create additional transactions. They will typically follow the PCs used 5 on the source transactions for which they are based. 6 7 Q. PLEASE DESCRIBE THE TIME ENTRY SYSTEMS USED BY THE 8 ENTERGY COMPANIES. 9 A. The Entergy Companies use both the PeopleSoft Time & Labor system 10 and the ESTER system for time entry. ESTER is the acronym for 11 “Entergy’s System for Time Entry and Reporting.” Both systems are 12 electronic time and attendance systems and are an important part of the 13 Entergy Companies’ cost and service tracking process. Employees or 14 timekeepers are responsible for populating electronic timesheets each pay 15 period with appropriate accounting codes, including PCs, and actual hours 16 worked, among other things. At the end of each pay period, the 17 employee’s supervisor is responsible for reviewing and approving the 18 timesheet data. 2011 ETI Rate Case 9-392 Entergy Texas, Inc. Page 47 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE SUMMARIZE THE CONTROLS THAT ARE IN PLACE TO 2 ENSURE THE ACCURACY OF THE INFORMATION RECORDED ON 3 THE TIMESHEETS IN TIME & LABOR AND ESTER. 4 A. In addition to the individual responsibilities of employees and supervisors 5 described above, both the Time & Labor and ESTER systems have been 6 programmed with certain validation functionality (e.g., validity and 7 compatibility edits for the accounting code input data) and notification 8 procedures to alert the employee when accounting code values, including 9 PCs, are invalid, incompatible, or incomplete. Training on the Time & 10 Labor and ESTER systems is conducted within each department. 11 Assistance is also available through the payroll administrator and through 12 the Financial Processes Help Desk, also referred to as the Financial 13 Operations Center (“FOC”) Help Desk. 14 Each ESI employee is ultimately responsible for charging the costs 15 that he or she incurs to the appropriate PC, and thus appropriately billing 16 the companies receiving the services. As a guide, ESI Time and Expense 17 Training materials are posted on the Affiliate Accounting and Allocations 18 section of the Entergy Companies’ internal web. All ESI employees are 19 required to acknowledge their review of these training materials on an 20 annual basis. This training stresses the importance of choosing the 21 correct PC. It also discusses the role of billing methods in billing the 22 appropriate companies for services rendered, and emphasizes that direct 23 billing is preferred over allocating charges where possible. The training 2011 ETI Rate Case 9-393 Entergy Texas, Inc. Page 48 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 also reviews how to determine which PC should be used for specific 2 services. These ESI Time and Expense Training materials are included 3 as Exhibit SBT-16. 4 As discussed earlier in my testimony, and as discussed in 5 Attachment 8 of Exhibit SBT-15, there are several other controls in place 6 to ensure that billings to affiliates properly reflect the actual cost of an item 7 or service. 8 9 Q. HOW ARE PROJECT CODES INITIATED AND MADE AVAILABLE FOR 10 USE? 11 A. As I previously mentioned, the Entergy Companies use a project costing 12 application (PowerPlant) that provides a single point of entry for all PCs. 13 When a particular department determines that a new project or service is 14 being initiated, PowerPlant is used by that department to set up the PC. 15 During set-up, the preparer of the PC request enters several elements to 16 establish a PC. The preparer provides a descriptive title for the PC and 17 determines the appropriate billing method, which may directly bill one 18 affiliate or allocate costs to multiple affiliates. The billing method is 19 determined based on cost causation principles for the particular project. 20 The preparer also describes the scope of the PC, including its overall 21 purpose, the primary activities to be performed, the products or 22 deliverables expected, and a justification of the billing method selected. 2011 ETI Rate Case 9-394 Entergy Texas, Inc. Page 49 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 This scope, as well as all of the attributes associated with the PC, are 2 stored in PowerPlant and can be referenced by users as needed. 3 Exhibit SBT-15 includes a more detailed discussion of the project 4 billing process used by ESI. A breakdown of ESI’s billings by project code 5 is shown in Exhibit SBT-8. 6 7 Q. DOES THE AFFILIATE BILLING PROCESS ENSURE THAT THE COSTS 8 CHARGED BY ESI TO ETI ARE NO HIGHER THAN THE COSTS 9 CHARGED TO OTHER AFFILIATES FOR THE SAME OR SIMILAR 10 ACTIVITIES AND SERVICES? 11 A. Yes. The following features of the billing system help ensure that ESI 12 does not charge a higher unit cost to ETI than to other affiliates for the 13 same or similar activities and services: 14 1) ESI always bills its services to regulated companies at cost, 15 with no profit added, based on cost causation; 16 2) the billing method is selected based on the principle of cost 17 causation to ensure that every affiliate that causes the cost 18 in the PC is appropriately included in the allocation of costs; 19 and 20 3) because each PC has only one billing method associated 21 with it, all affiliates that receive the service are charged at 22 the same unit rate for a given PC; therefore, the cost for a 23 given unit of service is equal for all affiliates receiving the 24 service. 2011 ETI Rate Case 9-395 Entergy Texas, Inc. Page 50 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. HOW DOES THE AFFILIATE BILLING PROCESS ENSURE THAT THE 2 PRICE CHARGED BY ESI TO ETI REPRESENTS THE ACTUAL COST 3 OF SERVICES? 4 A. With respect to direct billings, because ESI charges no more than actual 5 costs for services provided to regulated companies, the price charged to 6 ETI represents the actual cost. With respect to allocated costs, because 7 ESI charges the regulated companies at cost and utilizes the principle of 8 cost causation in identifying a billing method, the unit price charged to ETI 9 represents the actual cost. 10 11 Q. DOES YOUR TESTIMONY INCLUDE A SUMMARY OF CONTROLS TO 12 ENSURE THE ACCURACY OF THE ESI AFFILIATE BILLINGS? 13 A. Yes. Those controls are generally summarized in the Affiliate Billing 14 Process section of my testimony. In addition, these controls are 15 discussed in more detail in Attachment 8 of Exhibit SBT-15. 16 17 Q. ARE THERE ANY REVIEWS OF THE CONTROLS OVER THE 18 ACTIVITIES AND SERVICES AND THE RELATED COSTS THAT ESI 19 PROVIDES? 20 A. Yes. Internal Audit reviews the controls and performs tests of transactions 21 and balances related to affiliate billings. Specifically related to the 22 implementation of the Sarbanes-Oxley Act, Internal Audit reviews the 23 risks, control activities, and testing of those control activities associated 2011 ETI Rate Case 9-396 Entergy Texas, Inc. Page 51 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 with the affiliate billing process. Their review includes the related funding, 2 allocations, and intercompany account reconciliation processes 3 associated with the overall affiliate billing process. 4 In addition, external reviews and audits of affiliate transactions and 5 processes are conducted routinely. For instance, D&T performs certain 6 agreed upon procedures annually at the request of the Entergy 7 Companies to satisfy a requirement included in an October 1992 8 Settlement Agreement, as amended, between certain regulators and the 9 Entergy Companies that pertains to billings from affiliates to EEI. D&T 10 selects several intercompany transactions billed to EEI by affiliates to 11 ensure that they were billed in accordance with PUHCA 2005 affiliate 12 billing requirements. D&T’s “Independent Accountants’ Report on 13 Applying Agreed-Upon Procedures” for the year ended December 31, 14 2010, is included as Attachment 9 to Exhibit SBT-15. 15 In addition, the annual external audit of Entergy Corporation and its 16 subsidiaries’ financial statements performed by D&T helps to detect 17 whether the inter-company accounts and billing processes are producing 18 any material misstatements in the financial statements. The Sarbanes- 19 Oxley Act also requires that an independent auditor attest to the accuracy 20 of the Entergy Companies’ disclosure regarding the effectiveness of its 21 internal controls. In this connection, D&T also reviews risks, control 22 activities, and testing of control activities associated with the affiliate 23 billing processes. 2011 ETI Rate Case 9-397 Entergy Texas, Inc. Page 52 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Further, in its oversight role under PUHCA 2005, the FERC is 2 authorized to conduct audits of Entergy service company transactions. As 3 discussed earlier in my testimony, the most recent FERC audit of the four 4 service companies, including ESI, covered the period January 2006 5 through December 2008. 6 7 Q. DO YOU HAVE ANY INDEPENDENT VERIFICATION THAT THE 8 CONTROLS ARE FUNCTIONING PROPERLY? 9 A. Yes. PwC performed an independent attestation examination of 10 management’s assertion on the presentation of costs billed by ESI and 11 other Entergy affiliates to ETI for the twelve-months ended June 30, 12 2011.15 PwC’s attestation examination included, among other things, 13 (1) consideration of controls surrounding the affiliate billing process; 14 (2) documentation included in the PC scope statements, including a 15 description of the PC’s use and purpose, the activities associated with that 16 particular project, the expected deliverables from activities in the project, 17 and justification for the billing method to be used for billing the costs 18 accumulated in the project; and (3) testing of affiliate service charges 19 billed during the test year for this docket. 15 Workpaper WP/SBT-4 includes ESI’s management assertion and PwC’s report in connection with this attestation examination. 2011 ETI Rate Case 9-398 Entergy Texas, Inc. Page 53 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE EXPLAIN WHAT YOU MEAN BY “PC SCOPE STATEMENTS.” 2 A. A PC scope statement is a narrative description of the work that is to be 3 undertaken to which each PC is assigned. The PC scope statements, 4 included as part of the Project Summaries in my Exhibit SBT-E, provide 5 information regarding the purpose of the project, the primary activities to 6 be undertaken under the project, the primary products or deliverables of 7 the project, the billing method that applies to the project, and the 8 justification for that billing method. I have discussed the contents of these 9 Project Summaries in more detail previously in my testimony. 10 11 Q. PLEASE SUMMARIZE YOUR UNDERSTANDING OF PWC’S 12 CONCLUSIONS RELATING TO AFFILIATE SERVICE CHARGES. 13 A. PwC’s independent attestation examination of management’s assertion on 14 the presentation of costs allocated by ESI and other affiliates to ETI 15 concluded that management’s assertion was fairly stated in all material 16 respects. Management asserted that ESI has allocated costs 17 accumulated in identified PCs on a cost causative basis using billing 18 methods that ensure accurate recording and billing of the costs associated 19 with the provision of the related services. Management further asserted 20 that billing methods used to allocate costs by ESI ensure that costs 21 charged to ETI reasonably approximate the actual costs of services 22 provided and are no higher than the costs charged to other affiliates for 23 similar services. 2011 ETI Rate Case 9-399 Entergy Texas, Inc. Page 54 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE SUMMARIZE YOUR UNDERSTANDING OF PWC’S 2 CONCLUSIONS RELATING TO PC SCOPE STATEMENTS. 3 A. PwC concluded that management’s assertion regarding the PC scope 4 statements was fairly stated in all material respects, i.e., the PC scope 5 statements adequately described the project purpose, primary activities, 6 products or deliverables, and rationale for billing method assignment. 7 8 Q. DOES THE TOTAL ETI ADJUSTED AMOUNT ON THE G-6 9 SCHEDULES INCLUDE THE RECOMMENDATIONS MADE BY PWC AS 10 A RESULT OF ITS ATTESTATION EXAMINATION OF MANAGEMENT’S 11 ASSERTION ON THE PRESENTATION OF COSTS ALLOCATED BY 12 ESI AND OTHER AFFILIATES TO ETI? 13 A. Yes. The Total ETI Adjusted amount on the G-6 schedules reflects all of 14 the pro forma adjustments on Exhibit SBT-D. This exhibit includes various 15 adjustments due to PC billing method changes (Pro Forma Number AJ21- 16 04). The net effect of these adjustments is an increase in costs billed to 17 ETI of $7,368 which is included in the Total ETI Adjusted amount in test 18 year affiliate charges. 2011 ETI Rate Case 9-400 Entergy Texas, Inc. Page 55 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 B. Summary of ESI Billings to Affiliated Companies 2 Q. WHAT WERE TOTAL BILLINGS FROM ESI TO THE AFFILIATED 3 COMPANIES DURING THE TEST YEAR? 4 A. ESI billed approximately $883 million to its affiliate companies during the 5 test year for services provided. The following exhibits to my testimony 6 contain schedules that present views of ESI billings to affiliates: 7 Exhibit SBT-8 - ESI Test Year Per Book Billings to Affiliates 8 by Project 9 Exhibit SBT-17 – Direct vs. Allocated ESI Test Year Per 10 Book Billings to Affiliates 11 12 Q. WHAT HAPPENS TO CHARGES THAT ARE BILLED BY ESI TO THE 13 OTHER SERVICE COMPANIES, SUCH AS EOI AND EEI? 14 A. After ESI bills another service company for services rendered, the billed 15 service company affiliate in turn bills the costs to its affiliates. For 16 instance, when ESI bills EOI for services rendered, EOI will bill one or 17 more of the regulated nuclear plants that it serves (e.g., EGSL’s River 18 Bend facility) for the cost. When ESI bills EEI for services rendered, the 19 costs are billed by EEI to one or more of its affiliates. No costs billed by 20 ESI to EOI and EEI are subsequently billed by those Business Units 21 to ETI. 2011 ETI Rate Case 9-401 Entergy Texas, Inc. Page 56 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. WHAT IS THE LEVEL OF CHARGES FROM ESI TO ETI DURING THE 2 TEST YEAR? 3 A. ESI billed ETI approximately $84 million during the test year, or 4 approximately 9.5% of ESI’s total billings to all affiliates during the test 5 year (as seen on Exhibit SBT-8). This figure is a total per book number, 6 which includes expense and capital amounts billed to ETI. After taking 7 into account exclusions and pro forma adjustments for ESI charges billed 8 to ETI, the Total ETI Adjusted number is approximately $69 million (the 9 remaining $10 million of the Total Requested amount relates to charges 10 from other Entergy affiliates). 11 12 Q. HAVE THERE BEEN ANY CHANGES TO THE ESI BILLING PROCESS 13 SINCE THE COMMISSION’S LAST REVIEW OF THE AFFILIATE 14 BILLING PROCESS IN DOCKET NO. 37744? 15 A. With the exception of the changes in the Service Company Recipient 16 allocation process discussed later in my testimony, there have been no 17 substantive changes to the ESI billing process since the Commission’s 18 last review of ETI’s rates in Docket No. 37744. 2011 ETI Rate Case 9-402 Entergy Texas, Inc. Page 57 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 C. Billing Methods 2 1. Billing Method Overview 3 Q. IN SECTION VII.A ABOVE YOU DESCRIBED HOW A BILLING METHOD 4 CHOSEN FOR A PROJECT CODE ENSURES THAT ETI IS BILLED 5 ONLY THOSE COSTS ATTRIBUTABLE TO ETI. DO YOU HAVE AN 6 EXHIBIT THAT PROVIDES MORE INFORMATION REGARDING THE 7 BILLING METHOD ASSIGNMENT PROCESS? 8 A. Yes. As described in the billing process discussion in Exhibit SBT-15, 9 after the preparer of a PC request selects a billing method, it is reviewed 10 for reasonableness by both the intermediate approver of the PC and the 11 Affiliate Accounting and Allocations team that I oversee. If the billing 12 method selected does not appear to reflect cost-causation, the approver 13 may contact the preparer for clarification as to why the billing method was 14 chosen, or may reject the request until the billing method is adequately 15 justified or another billing method is selected to ensure that the billing 16 method is appropriate for the services provided under the PC. 17 Attachment 4 to Exhibit SBT-15 contains guidelines for preparing PC 18 scope statements, including the selection and justification of a cost- 19 causative billing method. 2011 ETI Rate Case 9-403 Entergy Texas, Inc. Page 58 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE EXPLAIN HOW ESI DEFINES “DIRECT” VERSUS 2 “ALLOCATED” BILLINGS. 3 A. ESI defines direct billings as those that are billed 100% to one affiliate. 4 Costs included in direct billings are incurred exclusively for the benefit of 5 one affiliate. ESI defines allocated billings as those that are distributed 6 using a formula that allocates costs to two or more affiliates. Costs 7 included in allocated billings are incurred for the benefit of more than 8 one affiliate. 9 10 Q. PLEASE DISTINGUISH BETWEEN THE TERMS “DIRECT,” 11 “ALLOCATED,” “INDIRECT,” AND “OVERHEAD.” 12 A. Each of these terms has been defined by ESI and the FERC. They are 13 also defined within the Service Agreements between ESI and its affiliates 14 that were accepted by the FERC in its December 12, 2006 order in 15 connection with ESI’s October 13, 2006 request for review and 16 acceptance of service company cost allocations. ESI’s definitions of the 17 terms “direct” and “allocated,” as used throughout this testimony, are 18 described in the preceding paragraph. These terms relate to how costs 19 are distributed – to one affiliate (direct), or to more than one affiliate 20 (allocated). The term “overhead” refers to costs that include (1) costs 21 necessary for the existence of ESI as an entity, and (2) costs that are 22 attributable to a department but aren’t related to any one specific project. 23 “Indirect” is a term used by ESI to also describe those costs that are 2011 ETI Rate Case 9-404 Entergy Texas, Inc. Page 59 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 attributable to the overall operation of a department and not to a specific 2 service. Exhibit SBT-18 is a chart showing how these terms are defined 3 by the three groups (ESI, the FERC, and the Service Agreements 4 accepted by the FERC) listed above. 5 6 Q. DOES ESI BILL DIRECTLY FOR SERVICES PROVIDED TO THE 7 REGULATED AFFILIATES WHENEVER APPROPRIATE? 8 A. Yes. The former SEC regulations required that service costs be billed 9 directly to an affiliate as long as such costs can be reasonably identified 10 as caused by an affiliate. Under PUHCA 2005, the FERC adopted this 11 “carryover” SEC provision. 12 However, it is important to note that the fundamental purpose of a 13 service company such as ESI is to achieve benefits from consolidation 14 and economies of scale for multiple companies. Therefore, the bulk of 15 ESI’s costs may necessarily be incurred to provide common services 16 required by multiple companies, which require an allocation of costs. For 17 example, there are several filings that are required by regulatory agencies 18 that include information for numerous affiliates. Because one filing often 19 serves multiple legal entities, the employees working on that document will 20 charge their time using a PC that employs an allocation factor that 21 represents a cost-causative relationship to the work performed. 22 Direct billings from ESI to ETI were 26.36% of ETI’s total charges 23 from ESI during the test year. Although each of the Operating Companies 2011 ETI Rate Case 9-405 Entergy Texas, Inc. Page 60 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 received a similar mix between allocated and direct billings, ETI had the 2 second highest percentage of direct ESI billings of all Entergy Operating 3 Companies during the test year. Exhibit SBT-17 depicts the percentage of 4 direct versus allocated billings from ESI to each of the affiliates to which 5 ESI provides service. 6 7 Q. DOES ESI DIRECTLY BILL EEI FOR SERVICES PROVIDED TO EEI ON 8 BEHALF OF THE NON-REGULATED AFFILIATES WHENEVER 9 APPROPRIATE? 10 A. Yes. As noted above, the Operating Companies have similar operations, 11 which provide opportunities for consolidation of services provided to them 12 by ESI. Although the provision of similar services by a single provider 13 results in economies of scale, this often requires an allocation of costs 14 instead of direct charging. However, because Entergy Corporation’s 15 non-regulated subsidiaries require many services that are not similar to 16 those of the regulated utility Operating Companies, the non-regulated 17 companies are not likely to share as many “consolidated” services as the 18 regulated companies. Instead, because of the variation in requested 19 services provided to the non-regulated affiliates, direct billings to the non- 20 regulated affiliates occur more often than direct billings to the Entergy 21 Operating Companies. As shown on Exhibit SBT-17, direct billings to EEI 22 (which receives the majority of non-regulated billings and, in turn, bills the 23 appropriate subsidiary) represent 46.5% of the total billings by ESI to EEI. 2011 ETI Rate Case 9-406 Entergy Texas, Inc. Page 61 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 As noted above, many services provided by ESI to non-regulated affiliates 2 are billed by ESI to EEI, rather than to the individual non-regulated 3 affiliates that receive those services. This does not mean, however, that 4 ESI is “underbilling” the non-regulated affiliates for the services they 5 receive. The billing methods applied to the project codes applicable to 6 these services ensure that the non-regulated affiliates are paying for their 7 applicable share of these costs (if allocated), or the full cost if the project 8 code direct bills the entire cost to EEI. Exhibit SBT-15 Attachment 6c 9 includes the statistics of each non-regulated company that were included 10 in calculating billing methods. 11 12 Q. DOES ESI EVER USE MORE THAN ONE BILLING METHOD FOR A 13 GIVEN PC? 14 A. No. Because each PC captures a specific service, each PC has only one 15 billing method assigned to it, and the billing method is selected to ensure 16 that every affiliate receiving the service also receives an appropriate 17 allocation. Therefore, the costs related to all services performed under a 18 PC that is not directly billed are allocated among affiliates using the same 19 criterion (such as number of accounts payable transactions or number of 20 customers). The use of a single billing method ensures that all affiliates 21 causing costs to be incurred and receiving the service pay an appropriate 22 proportion of the costs. This also ensures that the affiliates are, in total, 23 charged no more and no less than 100% of the costs for services provided 2011 ETI Rate Case 9-407 Entergy Texas, Inc. Page 62 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 under the PC. Also, the use of a single billing method, which is assigned 2 based on cost causation principles, ensures that each affiliate is paying 3 the same per unit price for the same service, and that the prices charged 4 to ETI are no higher than the prices charged by ESI to the other affiliates 5 for similar services. 6 7 Q. AFTER THE COSTS OF ESI’S SERVICES ARE CAPTURED BY A PC, 8 HOW ARE COSTS ALLOCATED AMONG THE APPROPRIATE 9 COMPANIES? 10 A. One billing method is assigned to each PC for each service company. 11 Depending on the assigned billing method, the cost of services rendered 12 will be billed directly to a single affiliate or allocated among several 13 affiliates. Billing methods are based on allocation formulae. Under 14 PUHCA 2005, these allocation formulae must be reviewed and accepted 15 by the FERC. Each allocation formula is based on data relevant to the 16 affiliated companies. 17 There are approximately 50 formulae currently in use by ESI that 18 are used to derive billing methods. The FERC has reviewed and accepted 19 each of these formulae. Examples of these allocation formulae are: total 20 average number of customers, number of personal computers, and 21 transmission line miles. 22 One allocation formula may be the basis of several billing methods 23 used in the project billing process. For example, ESI has several billing 2011 ETI Rate Case 9-408 Entergy Texas, Inc. Page 63 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 methods that use the total number of customers allocation formula, 2 including: Billing Method CUSEOPCO, based on average electric 3 customers for the utility Operating Companies; and Billing Method 4 CUSTEGOP, based on average electric and gas customers for the utility 5 Operating Companies. Billing methods that use a common basis for 6 allocation, such as those mentioned above, are referred to collectively as 7 a “billing method family.” Attachment 6b to Exhibit SBT-15 provides the 8 billing methods used during the test year. This exhibit includes each 9 billing method, the title of each billing method, and the percentage of total 10 costs allocated to each affiliate for each billing method. 11 12 Q. PLEASE SUMMARIZE HOW THE BILLING METHODS WORK. 13 A. Services that are provided by ESI to only one affiliate are billed using 14 direct billing methods, which by definition bill only one affiliate. Services 15 that are provided to more than one affiliate are allocated in accordance 16 with formulae reviewed and accepted by FERC. As previously discussed, 17 billing methods that distribute costs using these formulae are often termed 18 allocation methods. There were 179 direct and allocated billing methods 19 derived from FERC-accepted formulae in order to bill ESI affiliate costs to 20 the affiliated companies during the test year. Of these billing methods, 21 approximately 40% are direct billing methods (one billing method for each 22 business unit ESI serves directly), and the remainder represent variations 23 of the allocation formulae, as discussed above. However, as noted on 2011 ETI Rate Case 9-409 Entergy Texas, Inc. Page 64 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Attachment 7 of SBT-15, only 74 of the 179 ESI billing methods were used 2 to bill costs to ETI during the test year as reflected in the Total ETI 3 Adjusted amount. 4 5 2. Billing Method Calculations 6 Q. WHAT ARE THE ESI ALLOCATION BILLING METHODS (“ALLOCATION 7 METHODS”) THAT WERE USED TO BILL COSTS FOR SERVICES TO 8 ETI DURING THE TEST YEAR? 9 A. Exhibit SBT-19 is a chart that includes each ESI allocation method that 10 was used to bill costs to ETI during the test year. The chart provides the 11 billing method number, the billing method family to which each method is 12 associated, the basis on which the method is calculated, and the types of 13 costs that are allocated using each method. 14 15 Q. DID ESI USE ANY ALLOCATION METHODS TO ALLOCATE COSTS TO 16 ETI DURING THE TEST YEAR OTHER THAN THOSE INCLUDED IN 17 EXHIBIT SBT-19? 18 A. No. 19 20 Q. PLEASE DESCRIBE HOW EACH ALLOCATION METHOD EMPLOYED 21 BY ESI DURING THE TEST YEAR IS CALCULATED. 22 A. Each allocation method is calculated by taking each business unit’s pro 23 rata share of the cost driver statistics (such as number of accounts 2011 ETI Rate Case 9-410 Entergy Texas, Inc. Page 65 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 payable transactions or number of employees). For each allocation 2 method, Attachment 6 of Exhibit SBT-15 includes the percentages 3 allocated to each affiliate as well as the statistics used to come up with 4 those percentages. For Attachment 6b, all non-regulated percentages 5 and statistics are included in the “EEI” column. Attachment 6c was 6 prepared to provide the individual non-regulated companies included in 7 the statistics for “EEI.” 8 Previously required by the SEC under PUHCA 1935 and now 9 recognized by FERC under PUHCA 2005, all ESI services to ETI are 10 billed at cost. The specific billing method chosen for a particular type of 11 charge is selected to provide an appropriate matching of costs with the 12 cost drivers. Every affiliate that causes the cost and receives the service 13 provided is included in the cost allocation. 14 15 D. Service Company Recipient Allocation (also referred to as Shared 16 Services Loader) 17 Q. DOES THE ESI AFFILIATE BILLING PROCESS INCLUDE A 18 MECHANISM THAT CAPTURES AND ALLOCATES THE COSTS 19 ASSOCIATED WITH SERVICES THAT ESI PROVIDES TO ITSELF? 20 A. Yes. In addition to being the provider of services to affiliates, ESI also 21 provides services to itself so that it, in turn, can provide services to its 22 affiliates. Therefore, under cost causation billing, ESI is also a receiver of 23 costs associated with the services it provides. The mechanism that 2011 ETI Rate Case 9-411 Entergy Texas, Inc. Page 66 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 allocates the costs associated with the services ESI receives is currently 2 known as the “Service Company Recipient Allocation.” This allocation is 3 actually comprised of several types of costs, including information 4 technology, desktops and telephones (discussed more specifically by 5 Company witness Julie F. Brown), facilities-related costs such as rents 6 and space management (discussed more specifically by Company witness 7 Thomas C. Plauché), Human Resources-related costs (discussed more 8 specifically by Company witness Kevin G. Gardner), and the like. 9 10 Q. HOW DOES ESI CAPTURE THE COSTS ASSOCIATED WITH ESI 11 SERVICES RECEIVED? 12 A. ESI captures the costs associated with ESI services received by including 13 ESI as one of the legal entities to which ESI costs may be billed. 14 Examples of cost causative allocation methods of which ESI is a recipient 15 are APTRNALL (Accounts Payable Transactions), GENLEDAL (General 16 Ledger Transactions), and PRCHKALL (Payroll Checks Issued). Because 17 ESI creates Accounts Payable (“AP”) invoices, has its own General 18 Ledger (“GL”) transactions, and has employees who receive payroll 19 checks, a portion of the costs are caused by ESI. Also, like other 20 affiliates, ESI may directly bill costs to itself for services solely caused by 21 ESI using a direct billing method. Examples of costs that may be directly 22 billed to ESI are office supplies, professional fees, and rent associated 23 with ESI employees only. 2011 ETI Rate Case 9-412 Entergy Texas, Inc. Page 67 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. WHERE DOES ESI RECORD THE COSTS ASSOCIATED WITH ESI 2 SERVICES THAT ARE BILLED TO ESI? 3 A. During the PC billing process, all ESI expenses billed to ESI are deferred 4 on the balance sheet using a clearing account (Account 184SSL). In 5 particular, all of the costs received by ESI in the PC billing process are 6 assigned to Account 184SSL and further separated by the following 7 functions: Information Technology, Support – Operations, Support – 8 Corporate, Supply Power – Nuclear, and President/CEO. 9 10 Q. HOW ARE THE COSTS ACCUMULATED IN ACCOUNT 184SSL 11 ALLOCATED? 12 A. A second-tier allocation called Service Company Recipient Allocation 13 clears the Account 184SSL balance and distributes the costs to the 14 affiliates that are using the services of ESI employees. This is also 15 consistent with cost causation principles. It is appropriate to bill 16 companies a pro-rata share of ESI costs based on the amount and type of 17 ESI services they receive because the demand for ESI services drives the 18 costs associated with ESI. 19 20 Q. PLEASE DESCRIBE THE SERVICE COMPANY RECIPIENT 21 ALLOCATION PROCESS. 22 A. During the PC billing process, both the “pool” and “basis” for the Service 23 Company Recipient Allocation are created. The pool is the portion of 2011 ETI Rate Case 9-413 Entergy Texas, Inc. Page 68 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 monthly costs associated with services received by ESI, which occurs 2 when ESI bills itself. Such costs within this pool are identified by function. 3 The basis is the total monthly labor billings to each affiliate to which ESI 4 provides services in a given month. Such billings are also identified by 5 function. Thus, a loader rate for each function can be calculated. 6 7 Q. HOW IS THE LOADER RATE CALCULATED? 8 A. The loader rate for each function is determined by dividing the total 9 amount of costs in the pool for a function for that month by the total 10 amount of labor billings (the basis) to affiliates for each function for the 11 same month. Though typically stable, the monthly loader rates may vary 12 as the functional pool and basis vary. The loader rate then is applied to 13 labor billing results to distribute the costs in the pool. The Affiliate 14 Accounting and Allocations group reviews the pool and basis amounts 15 monthly to ensure that they are reasonable. 16 17 Q. PLEASE PROVIDE AN EXAMPLE OF THE SERVICE COMPANY 18 RECIPIENT ALLOCATION PROCESS. 19 A. In the following example, the Human Resources (“HR”) department 20 provides staffing services to the Fossil organization. The HR employees 21 assign their time to a PC that bills based on the number of fossil-fueled 22 generation plant (“Fossil”) employees within each Entergy Corporation 23 subsidiary. Because ESI has Fossil employees, ESI receives a portion of 2011 ETI Rate Case 9-414 Entergy Texas, Inc. Page 69 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 the billing, which is assigned to the 184SSL account. This is classified as 2 an overhead cost for ESI Fossil employees. During the same billing 3 process, ESI Fossil employees bill their labor out to those companies 4 receiving their services via the billing method assigned to each PC used. 5 Once the PC billing process described above is complete, the 6 Service Company Recipient Allocation begins. In this second-tier 7 allocation, the total dollar amount that was billed to ESI for services 8 provided to ESI Fossil employees by Human Resources (contained within 9 the Support-Corporate pool) is distributed to the labor amounts that were 10 billed by the ESI Fossil group (the basis), thereby loading the Fossil 11 organization’s labor billings with their share of service company 12 recipient charges. 13 14 Q. WHY DOES ESI USE THIS TWO-TIERED APPROACH FOR BILLING? 15 A. The two-tiered approach is used to ensure that all the costs (both 16 overhead and direct) are paid for by the affiliates that cause the costs. It 17 is important that ETI be able to determine the total cost associated with its 18 projects and services. The Service Company Recipient Allocation 19 ensures that overheads associated with managing each ESI function are 20 loaded to the projects to which those functional employees charged their 21 time. This enables each project to be fully-loaded with both the direct 22 costs assigned to the project as well as service company 23 recipient charges. 2011 ETI Rate Case 9-415 Entergy Texas, Inc. Page 70 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. HAVE THERE BEEN ANY CHANGES IN THIS PROCESS SINCE THE 2 COMMISSION’S LAST REVIEW IN DOCKET NO. 37744? 3 A. Yes. The Service Company Recipient Allocation’s basis was adjusted in 4 January 2010 to include not only labor billings to ESI affiliates, but also 5 labor costs that remain at ESI such as capital or other balance sheet items 6 maintained at ESI. Prior to the change, the basis included only labor 7 billings to affiliates from ESI. As a result of the change, ESI-owned capital 8 projects (not included in cost of service) are loaded with the service 9 company recipient charges as well. In addition, beginning in January 10 2010, the number of functional rates was changed from sixteen to five. 11 This change was implemented to streamline the process so that internal 12 customers could more easily analyze and predict their service company 13 recipient costs. 14 15 E. Payroll Loaders 16 Q. WHAT ARE PAYROLL LOADERS? 17 A. Payroll loaders allocate payroll-related costs, specifically payroll taxes, 18 employee benefits, post-employment benefits, stock options, certain 19 incentive compensation, and paid time off. Each of these costs has its 20 own loader. These payroll-related costs are loaded to projects so that 21 each project is fully-loaded with both the direct labor costs and the 22 associated payroll loaders. 2011 ETI Rate Case 9-416 Entergy Texas, Inc. Page 71 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE SUMMARIZE THE PAYROLL LOADERS PROCESS. 2 A. The Human Resources department provides Affiliate Accounting and 3 Allocations with base standard rates for employee benefits, post- 4 employment benefits, and stock options, while the Compensation and 5 Benefits Design department provides the base standard rates for 6 incentives. These base standard rates are based on total payroll. The 7 base standard rate for payroll taxes is calculated by the Affiliate 8 Accounting and Allocations group based on payroll taxes paid during the 9 prior year as a percentage of the total payroll paid during the prior year. 10 Because payroll allocations load only on productive payroll rather than 11 total payroll, the Affiliate Accounting and Allocations group adjusts these 12 base standard rates by productive factors to generate actual loader rates. 13 The actual loader rate for paid time off is also calculated by the Affiliate 14 Accounting and Allocations group based on the percentage of non 15 productive payroll to productive payroll. 16 The loader rates for employee benefits, post-employment benefits, 17 stock options, incentives, and paid time off are applied to productive 18 straight-time payroll (excluding overtime). The loader rate for payroll taxes 19 is applied to total productive payroll (including overtime). All loaders are 20 assigned the same PC as the labor, so that they properly follow the same 21 billing distribution as the labor dollars on which they are based. As I 22 explained earlier in my testimony, each PC is assigned one billing method 2011 ETI Rate Case 9-417 Entergy Texas, Inc. Page 72 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 that will most appropriately allocate the charges to the companies 2 receiving the services based on cost-causation principles. 3 4 Q. HOW OFTEN ARE LOADER RATES REVIEWED AND ADJUSTED, IF 5 NEEDED? 6 A. The loader rates for payroll taxes, employee benefits, post-employment 7 benefits, stock options, incentives, and paid time off, are reviewed for 8 reasonableness by the Affiliate Accounting and Allocations group on a 9 quarterly basis and adjusted, or trued-up, on an annual basis. 10 11 Q. HAVE THERE BEEN ANY CHANGES IN THIS PROCESS SINCE THE 12 COMMISSION’S LAST REVIEW IN DOCKET NO. 37744? 13 A. Yes. In Docket No. 37744 (test period including the twelve months ended 14 June 30, 2009) the payroll loaders included employee benefits, post- 15 employment benefits, incentives, payroll taxes, and paid time off. The 16 post-employment benefits loader was comprised of payroll related costs 17 associated with stock options, pensions, and other post-employment 18 benefits. In July 2010, the payroll related costs associated with stock 19 options were separated into its own payroll loader. The stock option 20 payroll loader was created to identify those costs with a separate, unique 21 resource code. The post-employment benefits loader now excludes the 22 payroll related costs associated with stock options. 2011 ETI Rate Case 9-418 Entergy Texas, Inc. Page 73 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 VIII. OTHER AFFILIATE BILLINGS 2 Q. BESIDES ESI, WHICH ENTERGY COMPANIES BILLED ETI FOR 3 SERVICES RENDERED DURING THE TEST YEAR? 4 A. Each of the Operating Companies billed ETI for services rendered. There 5 are several reasons for the Operating Companies to provide services to 6 one another. For instance, materials from the storeroom of one Operating 7 Company are often transferred to another. Also, one Operating Company 8 may assist another in an emergency situation, such as during a storm and 9 subsequent storm restoration. An Operating Company affiliate can also 10 transfer a percentage of the operating costs of a shared plant to another 11 Operating Company affiliate through the co-owner billing process. As 12 noted previously, during the test year, EGSL transferred operating costs to 13 ETI related to the jointly-owned Nelson 6 plant. In addition, certain of 14 Entergy Corporation’s non-regulated affiliates also loaned services to ETI. 15 These services primarily relate to loaned labor and material transfers. 16 The following exhibits provide a listing of test year per book billings 17 by project/activity code for each Operating Company to its affiliates and for 18 non-regulated affiliates to the regulated affiliates: 19 Exhibit SBT-20 – Entergy Arkansas Billings to Affiliates; 20 Exhibit SBT-21 – Entergy Gulf States Louisiana Billings to 21 Affiliates; 22 Exhibit SBT-22 – Entergy Louisiana Billings to Affiliates; 23 Exhibit SBT-23 – Entergy Mississippi Billings to Affiliates; 2011 ETI Rate Case 9-419 Entergy Texas, Inc. Page 74 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Exhibit SBT-24 – Entergy New Orleans Billings to Affiliates; 2 and 3 Exhibit SBT-25 – Entergy Non-Regulated Affiliates Billings to 4 Regulated Affiliates 5 6 IX. SPONSORED CLASSES OF AFFILIATE COSTS 7 A. Overview 8 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY? 9 A. I sponsor the following three classes of affiliate costs: 10 (1) Depreciation. The Depreciation Class includes the cost for 11 the depreciation and amortization of ESI assets. These 12 assets are used by ESI in the provision of services to its 13 affiliate companies; 14 (2) Service Company Recipient Offsets. The Total ETI Adjusted 15 amount for the Service Company Recipient Offsets Class is 16 zero. This class is set up for Accounting purposes only; and 17 (3) Other Expenses. The Other Expenses Class primarily 18 includes payroll-related costs that have not yet been loaded 19 to individual departments, the credit ETI received from the 20 5% upcharge to the non-regulated affiliates, and other 21 miscellaneous costs not associated with other specific 22 classes. 23 As shown on my Exhibits SBT-5 and SBT-6, these three classes 24 are in the Accounting Entries function, which is included in the Corporate 25 Support family. 26 27 Q. WITH REGARD TO THE THREE CLASSES THAT YOU SPONSOR, DO 28 THE BILLINGS PROVIDED TO ETI DURING THE TEST YEAR MEET 2011 ETI Rate Case 9-420 Entergy Texas, Inc. Page 75 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 THE COMMISSION STANDARDS FOR INCLUSION OF SUCH COSTS 2 IN RATES? 3 A. Yes. The billings to ETI during the test year in the three classes of costs 4 that I sponsor meet the Commission standards for inclusion of such costs 5 in rates (noting, again, that there are no costs from the Service Company 6 Recipient Offsets Class included in the Total ETI Adjusted amounts in this 7 case). Specifically: 8 1. The charges billed to ETI during the test year were 9 reasonable and necessary for the operation of ETI. 10 2. The amount charged to ETI through the PC billing process, 11 the co-owner billing process, and the loaned resource billing 12 process for each cost or class of costs during the test year 13 are no higher than the amount charged to the other affiliates 14 or non-affiliated persons for these classes of costs. 15 3. The amounts charged to ETI during the test year represent 16 the actual costs of services provided to ETI. 17 4. As with all other classes of affiliate costs, expenses that are 18 not allowed for ratemaking purposes are included in the 19 billed expenses, but are excluded from the Total ETI 20 Adjusted amount as below-the-line expenses in accounts 21 such as Account No. 426, and/or are included in the pro 22 forma adjustments shown on Schedule G-6.2, and, 23 therefore, are not included in cost of service. 24 5. The items charged to ETI are not duplicative of items already 25 provided by or for ETI. 2011 ETI Rate Case 9-421 Entergy Texas, Inc. Page 76 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 B. Depreciation Class 2 1. Description of Class 3 Q. PLEASE BRIEFLY DESCRIBE THE DEPRECIATION CLASS OF 4 AFFILIATE COSTS. 5 A. This class represents the cost of depreciation and amortization of ESI 6 assets. These assets are used by ESI for the provision of services to its 7 affiliate companies. 8 9 Q. WHAT IS THE TOTAL ETI ADJUSTED AMOUNT FOR THIS CLASS OF 10 SERVICES? 11 A. As shown in Exhibits SBT-A, SBT-B, and SBT-C, the Total ETI Adjusted 12 amount for this class of services is $1,777,986. Of this amount, ESI 13 directly billed 27% of the amount, and allocated 73% of the amount, to 14 ETI. The following table summarizes this information for the Depreciation 15 Class. The table shows for each class the following information: 2011 ETI Rate Case 9-422 Entergy Texas, Inc. Page 77 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case Total Billings Dollar amount of total Test Year billings and charges from ESI to all Entergy Business Units, plus the dollar amount of all other affiliate charges to ETI that originated from any Entergy Business Unit. This is the amount from Column (C) of the cost exhibits SBT-A, SBT-B, and SBT-C. Total ETI Adjusted ETI’s adjusted amount for electric cost of service after pro forma adjustments and exclusions. % Direct Billed The percentage of the ETI adjusted test year amount that was billed 100% to ETI. % Allocated The percentage of the ETI adjusted test year amount that was allocated to ETI. Total ETI Adjusted Class Total Billings Amount % Direct % Allocated Depreciation $26,406,546 $1,777,986 27% 73% 1 Q. PLEASE DESCRIBE THE EXHIBITS THAT SUPPORT THE 2 INFORMATION INCLUDED IN THE TABLE ABOVE. 3 A. Please see Exhibits SBT-A, SBT-B, and SBT-C, which I described above 4 in connection with my affiliate overview presentation. For each of these 5 exhibits, the amounts in the columns represent the following information: 2011 ETI Rate Case 9-423 Entergy Texas, Inc. Page 78 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case Column (A) – Dollar amount of total Test Year billings and Support charges from ESI to all Entergy Business Units, plus the dollar amount of all other affiliate charges to ETI that originated from any Entergy Business Unit. Column (B) – Dollar amount that was included in the service Service Company company recipient allocation. Service company Recipient recipient charges are the cost of services that ESI provides to itself, which in turn are charged to affiliates that receive those services. The service company recipient allocation process is described earlier in my testimony. Column (C) – Represents the sum of Columns (A) and (B). Total Column (D) – That portion of Column (C) that was billed and All Other BU’s charged to Business Units other than ETI. Column (E) – Represents the difference between Columns (C) ETI Per Books and (D). Column (F) – Represents amounts that are excluded from ETI Exclusions electric cost of service. The exclusions are described in my testimony. Column (G) – Pro Forma Amounts include adjustments for Pro Forma Amount known and measurable changes, and corrections. Column (H) – ETI adjusted amount requested for recovery in Total ETI Adjusted this case for this class (Column (E) plus Columns (F) and (G)). 1 I have explained the adjustments with respect to Column F 2 (Exclusions) and Column G (Pro Forma Amount) earlier in my testimony. 2011 ETI Rate Case 9-424 Entergy Texas, Inc. Page 79 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. ARE THERE ANY PRO FORMA ADJUSTMENTS TO THIS CLASS? 2 A. Yes. The pro forma adjustments for the Depreciation Class are shown on 3 Exhibit SBT-D, which also indicates the Company witnesses who sponsor 4 those pro forma adjustments, and lists the pro forma adjustments by 5 account. As indicated on Exhibit SBT-D, I sponsor three pro forma 6 adjustments to the Depreciation Class. Exhibit SBT-12 describes the pro 7 forma adjustments to the Depreciation Class in greater detail. 8 9 2. Necessity 10 Q. WHAT KINDS OF ASSETS ARE OWNED BY ESI THAT RESULT IN THE 11 DEPRECIATION THAT IS THEN CHARGED TO THE AFFILIATE 12 COMPANIES? 13 A. In order to provide services to its affiliate companies, ESI must invest in 14 certain depreciable assets to support its operations. These assets consist 15 primarily of computer equipment, computer software systems, 16 communications equipment, furniture, fixtures, leasehold improvements, 17 and aircraft. However, a pro forma adjustment was made to remove 18 Company aircraft costs, including depreciation on aircraft, from the 19 Company’s cost of service. 2011 ETI Rate Case 9-425 Entergy Texas, Inc. Page 80 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE DESCRIBE HOW THE DEPRECIATION OF ESI’S ASSETS IS 2 CALCULATED. 3 A. The purpose of depreciation is to distribute the cost of an asset over its 4 expected useful life. Total depreciation expense over the life of an asset 5 is equal to the asset’s cost (less any proceeds realized upon disposal). 6 ESI uses the straight-line method to calculate the annual depreciation 7 expense for its assets. Use of this depreciation method results in the cost 8 of an asset being distributed evenly over the expected useful life of the 9 asset. For example, an asset costing $1,000 that has an expected service 10 life of 10 years would result in depreciation expense for this asset of $100 11 per year for a period of 10 years ($1,000 divided by 10 years = $100 per 12 year or 10% a year). This method of calculating depreciation is 13 appropriate under generally accepted accounting principles. The straight- 14 line method is also the most commonly used and accepted depreciation 15 method. According to an American Institute of Certified Public 16 Accountants survey of 544 companies in 2009, 89% use the straight-line 17 method of depreciation versus other methods, which are primarily 18 accelerated methods of depreciation.16 Exhibit SBT-26 is a summary of 19 ESI’s assets, including plant in service, accumulated depreciation, net 20 plant, and the service life used to calculate depreciation. 16 American Institute of Certified Public Accountants (AICPA); Accounting Trends & Techniques – 2010. 2011 ETI Rate Case 9-426 Entergy Texas, Inc. Page 81 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE EXPLAIN WHY THE DEPRECIATION COSTS BILLED TO ETI 2 ARE NECESSARY. 3 A. ESI requires certain assets to support the operations that provide services 4 to its affiliates, including ETI. The depreciation cost is the result of 5 distributing the cost of these assets over their expected service lives to the 6 recipients of the services provided by ESI. These assets enable ESI to 7 provide the services required by its affiliates, including ETI, in the most 8 efficient, effective, and reliable manner possible. Without such assets to 9 support its operations, ESI could not provide the services that are required 10 by its affiliates, including ETI. Depreciation of those assets is a necessary 11 and proper component of the cost of owning and using the assets to 12 provide services. 13 14 3. Reasonableness 15 Q. HAVE YOU REVIEWED THE DEPRECIATION EXPENSE TO 16 DETERMINE WHETHER THE CHARGES WERE REASONABLE? 17 A. Yes. The charges to ETI for the costs I sponsor are reasonable for the 18 operation of ETI because the method of calculating depreciation 19 (straight-line method) is appropriate under generally accepted accounting 20 principles and is the most common method used. In addition, the price 21 charged by ESI to ETI for this item represents the actual cost of this item. 2011 ETI Rate Case 9-427 Entergy Texas, Inc. Page 82 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. WHAT OBJECTIVE SOURCES SUPPORT YOUR OPINION THAT THE 2 DEPRECIATION COSTS BILLED BY ENTERGY SERVICES TO ETI ARE 3 REASONABLE? 4 A. Exhibit SBT-27 is a benchmarking study prepared under my supervision 5 that compares the dollar amount of assets per employee for ESI to the 6 dollar amount of assets per employee for other PUHCA 2005 service 7 companies. This measure, cost of assets per employee, is appropriate 8 because employees drive the need for assets in service companies. 9 Because the number of employees would be the primary determinant of 10 the level of the assets that would be required, assets per employee is a 11 valid measure. Exhibit SBT-27 compares the service company property 12 per employee of ESI to the service company property per employee of six 13 other PUHCA 2005 service companies with at least $100 million of service 14 company property as of December 31, 2010. This exhibit shows ESI’s 15 cost of assets per employee, while slightly higher than the average, is 16 reasonable compared to that of the other PUHCA 2005 service 17 companies. This comparison is based on service company headcount 18 information contained in the respective corporate Forms 10-K and service 19 company property information contained in each service company’s FERC 20 Form 60 Annual Report for the period ending December 31, 2010. 21 However, the service company property for Southern Company 22 Services, Inc., Entergy Services, Inc., Exelon Business Services 23 Company, and American Electric Power Service Corporation on Exhibit 2011 ETI Rate Case 9-428 Entergy Texas, Inc. Page 83 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 SBT-27 differs from what was reported on the companies’ 2010 FERC 2 Form 60s. These were the only companies that included Transportation 3 Equipment in their Service Company Property. Beginning with the FERC 4 Form 60 Annual Report for the period ending December 31, 2008, the 5 service company property category “Aircraft and Airport Equipment” was 6 eliminated and included in “Transportation Equipment.” A pro forma 7 adjustment was made (AJ21-01) to remove Company aircraft costs from 8 the Company’s cost of service. Therefore, to be consistent with the costs 9 included in this case, the Transportation Equipment was removed from the 10 total Service Company Property for all companies before the 11 benchmarking study was completed. Because the benchmarking study 12 supports the reasonableness of the level of assets being depreciated, and 13 the procedures used to depreciate the assets are appropriate and 14 consistent with well accepted accounting practices, the ultimate level of 15 depreciation is likewise reasonable. 16 With the exception of depreciation on aircraft, ESI distributes the 17 costs associated with the depreciation and amortization of ESI assets 18 based on the labor cost billed to each affiliate. Distributing ESI’s 19 depreciation and amortization costs in this manner is an appropriate 20 allocation of these costs because ESI employee labor is a reasonable 21 measure of the level of services provided by ESI employees to affiliates, 22 and employees and the services they provide drive the need for the assets 23 utilized by ESI in its operations. Depreciation on aircraft is included as a 2011 ETI Rate Case 9-429 Entergy Texas, Inc. Page 84 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 component of total flight costs of ESI aircraft. Flight costs are charged to 2 specific PCs based on the PC(s) associated with the ridership and 3 purpose of a particular flight. However, as noted above, a pro forma 4 adjustment was made to remove Company aircraft costs, including 5 depreciation on aircraft, from the Company’s cost of service. 6 7 4. How Costs are Charged 8 Q. DO THE DEPRECIATION COSTS CHARGED BY ENTERGY SERVICES 9 TO ETI UNDER THIS CLASS REASONABLY APPROXIMATE THE 10 COSTS OF THOSE ITEMS? 11 A. Yes. The depreciation costs charged are based on the actual costs of the 12 assets supporting ESI’s operations and do not include any profit 13 or markup. 14 15 Q. IS THE PRICE CHARGED TO ETI FOR DEPRECIATION NO HIGHER 16 THAN THE PRICE CHARGED TO OTHER AFFILIATES? 17 A. Yes. The price charged to ETI is no higher than the price charged by ESI 18 to the other affiliates for depreciation on a per unit basis. With the 19 exception of depreciation on aircraft, ESI depreciation expense is loaded 20 onto each ESI labor dollar, and then billed out to affiliates. The 21 depreciation loader is assigned the same PC as labor, so that it properly 22 follows the same billing distribution as the labor dollars on which it is 23 based. As explained in my testimony, each PC is assigned one billing 2011 ETI Rate Case 9-430 Entergy Texas, Inc. Page 85 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 method that will most appropriately allocate the charges to the companies 2 receiving the services based on cost-causation principles. Thus, 3 depreciation cost is billed to each affiliate at the same rate for each dollar 4 of labor charged, ensuring that costs are equitably distributed to 5 each affiliate. 6 7 Q. HOW ARE THE COSTS OF THIS CLASS CAPTURED AND BILLED TO 8 ETI? 9 A. With the exception of depreciation on aircraft, the cost associated with this 10 class is initially captured in Project Code F5PCZUDEPX, Depreciation and 11 Amortization, and then these costs are distributed directly to ESI PCs 12 based on the labor charged to the project codes. The receiving PCs then 13 bill the depreciation costs (along with all other costs charged to the PC) to 14 ESI’s affiliates based on the assigned billing method for each project. 15 During the test year, projects receiving depreciation costs billed 16 $1,777,986 Total ETI Adjusted, which includes pro forma adjustments, to 17 ETI. Exhibit SBT-B shows the costs included in this class by project code. 18 19 Q. WHAT BILLING METHOD IS USED TO ALLOCATE THIS EXPENSE 20 ITEM TO THE VARIOUS ENTITIES THAT RECEIVE SERVICES FROM 21 ESI? 22 A. As noted, with the exception of depreciation on aircraft, ESI assigned 23 depreciation costs to projects based on labor charged to projects and then 2011 ETI Rate Case 9-431 Entergy Texas, Inc. Page 86 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 billed these costs to affiliates based on the billing method assigned to 2 each project. The use of assets required to support ESI employee service 3 functions results in the depreciation and amortization cost. Labor charged 4 to projects is an appropriate allocation for this cost because ESI employee 5 labor is a reasonable measure of the level of services provided by ESI 6 employees to affiliates. This process distributes the depreciation and 7 amortization of assets necessary for the ESI employees to provide 8 services to its affiliates in a manner consistent with the distribution of ESI 9 labor to the affiliates that receive services. 10 11 C. Service Company Recipient Offsets (also referred to as Shared Services 12 Loader Offsets) 13 1. Description of Class 14 Q. PLEASE BRIEFLY DESCRIBE THIS CLASS OF AFFILIATE COSTS. 15 A. This class represents the corresponding credit to Service Company 16 Recipient Allocation transactions. As discussed earlier in my testimony, 17 the Service Company Recipient Allocation is the mechanism by which the 18 costs of services provided by ESI employees to operate ESI that are 19 initially billed to ESI through the PC billing process are distributed to ESI’s 20 affiliates in a second tier allocation. ESI records the costs associated with 21 ESI services received in a “clearing account” on its balance sheet. These 22 costs reside temporarily in this clearing account until they are distributed 23 to affiliates that are using the services of ESI employees. There are two 2011 ETI Rate Case 9-432 Entergy Texas, Inc. Page 87 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 components of the Service Company Recipient Allocation process: the 2 recording of costs in the clearing account during the PC billing process; 3 and removal from or credit to the clearing account during the second tier 4 allocation process. Because the costs are distributed to all affiliates based 5 on the labor billings of ESI employees, the allocated costs are reflected in 6 the other affiliate classes. The loader offset, which is charged to a 7 balance sheet clearing account, is reflected in the Service Company 8 Recipient Offsets Class. Because the loader offset is charged to a 9 balance sheet account at ESI, loader offset amounts are not included in 10 the Total ETI Adjusted, as shown on my Exhibits SBT-A, SBT-B, and 11 SBT-C. 12 13 D. Other Expenses Class 14 1. Description of Class 15 Q. PLEASE DESCRIBE THIS CLASS OF AFFILIATE COSTS. 16 A. This class reflects $1,756,009 of costs resulting from certain accounting 17 adjustments. It primarily includes costs related to payroll, the credit from 18 the 5% upcharge to the non-regulated affiliates, and other miscellaneous 19 costs that are not associated with any other specific affiliate class. 2011 ETI Rate Case 9-433 Entergy Texas, Inc. Page 88 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q PLEASE DESCRIBE THE ADJUSTMENTS THAT RESULTED IN THE 2 PAYROLL-RELATED COSTS INCLUDED IN THIS CLASS. 3 A. Certain payroll-related adjustments, which resulted in the payroll-related 4 costs in this class, are primarily the result of the use of standard estimated 5 rates throughout the year, which differ from actual recorded charges at the 6 end of the year. The costs resulting from the payroll-related adjustments 7 account for approximately $2.3 million. (As I explain below, there is a 8 credit that offsets this amount by $500,000.) Company witness Gardner 9 discusses the reasonableness of various types of payroll-related costs, 10 including employee benefits, teamsharing, and other incentive 11 compensation and payroll taxes. I address the residual amount of these 12 payroll-related costs that have not been loaded to specific departments. 13 14 Q. BESIDES THESE PAYROLL-RELATED COSTS, WHAT OTHER COSTS 15 ARE INCLUDED IN THE OTHER EXPENSES CLASS? 16 A. Also included in the Other Expenses Class is a credit of approximately 17 $500,000 of other expenses. The other expenses within this class are 18 primarily made up of credits related to the 5% upcharge to the non- 19 regulated companies, and other miscellaneous accounting adjustments of 20 approximately $240,000. 2011 ETI Rate Case 9-434 Entergy Texas, Inc. Page 89 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. WHAT PERCENTAGES OF THE TOTAL ETI ADJUSTED FOR THIS 2 CLASS WERE DIRECT BILLED AND ALLOCATED TO ETI? 3 A. As shown on Exhibit SBT-A, SBT-B, and SBT-C, the Total ETI Adjusted 4 amount for this class of services is $1,756,009. Of this amount, ESI 5 directly billed the $500,000 credit described above (which is -13.9% of the 6 Total ETI Adjusted amount) and allocated the payroll-related costs (which 7 is 113.9% of the Total ETI Adjusted amount) to ETI. The following table 8 summarizes this information for the Other Expenses Class. I described 9 the column names previously in the Depreciation Class section of my 10 testimony. Total ETI Adjusted Class Total Billings Amount % Direct % Allocated Other Expenses $36,585,596 $1,756,009 -13.9% 113.9% 11 Q. PLEASE DESCRIBE THE EXHIBITS THAT SUPPORT THE 12 INFORMATION INCLUDED IN THE TABLE ABOVE. 13 A. Exhibits SBT-A through SBT-C support the information for this class in the 14 same manner as I discussed earlier in my testimony. For each exhibit, the 15 amounts in the columns represent the same information as described 16 above with regard to my Depreciation Class. 2011 ETI Rate Case 9-435 Entergy Texas, Inc. Page 90 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. ARE THERE ANY PRO FORMA ADJUSTMENTS TO THIS CLASS? 2 A. Yes. The pro forma adjustments for the Other Expenses Class are shown 3 on Exhibit SBT-D, which also indicates the Company witnesses who 4 sponsor those pro forma adjustments. As indicated on Exhibit SBT-D, 5 there were eleven pro forma adjustments made to the Other Expenses 6 Class. Exhibit SBT-12 describes the pro forma adjustments to this Class 7 in greater detail. 8 9 Q. WHAT ARE THE MAJOR COST COMPONENTS OF THE CHARGES 10 FOR THIS CLASS? 11 A. The major cost components for charges from ESI to ETI are as follows: Cost Component Dollars % of Total Payroll and Employee $2,280,649 129.88% Costs Outside Services $112,325 6.4% Office and Employee $1 0% Expenses Service Company $105,361 6% Recipient Other $-742,327 -42.27% TOTAL $1,756,009 100% 12 Q. WHAT IS THE IMPORTANCE OF THESE COST CATEGORIES? 13 A. The foregoing table is common to most affiliate witnesses in this case. I 14 directly sponsor the costs shown in this table because they comprise the 2011 ETI Rate Case 9-436 Entergy Texas, Inc. Page 91 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Total ETI Adjusted amount for the Other Expenses Class. This breakout 2 of costs provides an additional view of the components of the costs in this 3 class. For example, the table demonstrates that 129.88% of the costs are 4 for compensation, employee benefits, and other labor-related expenses 5 (“Payroll and Employee Costs”). These costs are the result of certain 6 payroll-related adjustments, which I discussed earlier in this section. 7 Company witness Gardner discusses overall payroll and benefits-related 8 structure and practices. The Other expenses in this class, as I previously 9 discussed, include the credits related to the 5% upcharge to the 10 non-regulated affiliates, and other miscellaneous accounting adjustments. 11 12 2. Necessity 13 Q. PLEASE EXPLAIN WHY THE ADJUSTMENTS THAT RESULTED IN 14 THE COSTS BILLED TO ETI UNDER THE OTHER EXPENSES CLASS 15 ARE NECESSARY. 16 A. As explained above, the adjustments resulting in the payroll-related costs 17 included in the Other Expenses Class are necessary to reflect costs 18 associated with reasonable and necessary compensation and benefit 19 programs that Company witness Gardner discusses in his direct 20 testimony. The remaining costs in this class were necessary to properly 21 reflect accounting entries in the Company’s books in accordance with 22 generally accepted accounting standards. 2011 ETI Rate Case 9-437 Entergy Texas, Inc. Page 92 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 3. Reasonableness 2 Q. HAVE YOU REVIEWED THE COSTS IN THE OTHER EXPENSES 3 CLASS TO DETERMINE WHETHER THE ADJUSTMENTS WERE 4 REASONABLE? 5 A. Yes. The adjustments that result in the payroll-related costs in the Other 6 Expenses Class are reasonable because they were made in accordance 7 with generally accepted accounting standards to reflect timing differences 8 associated with book entries. There is no duplication or over-recovery of 9 actual costs. The reasonableness of the compensation and benefit 10 programs associated with these payroll-related costs are discussed by 11 Company witness Gardner. As stated, the remaining adjustments are 12 reasonable (and necessary) to reflect proper and accepted accounting 13 practices with regard to the Company’s books. 14 15 4. How Costs are Charged 16 Q. DO THE COSTS CHARGED BY ESI TO ETI UNDER THE OTHER 17 EXPENSES CLASS REASONABLY APPROXIMATE THE COSTS OF 18 THOSE ITEMS? 19 A. Yes, they do. The costs charged under the Other Expenses Class, which 20 are the result of certain adjustments, are based on actual costs and do not 21 include any profit or markup. 2011 ETI Rate Case 9-438 Entergy Texas, Inc. Page 93 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. IS THE PRICE CHARGED TO ETI FOR ADJUSTMENTS CHARGED 2 UNDER THIS CLASS NO HIGHER THAN THE PRICE CHARGED TO 3 OTHER AFFILIATES? 4 A. Yes. The adjustments that resulted in the costs in this class ensure that 5 the total costs charged to ETI are no higher than the price charged by ESI 6 to the other affiliates for the costs charged under the Other Expenses 7 Class. The adjustments that resulted in the payroll-related costs in this 8 class are part of a true-up process to adjust payroll-related account 9 balances for the use of standard estimated rates during the year. The 10 account balance true-ups follow the same billing distribution as the original 11 payroll loaders with the same PCs used for labor costs. As I explained 12 earlier in my testimony, each PC is assigned one billing method that will 13 most appropriately allocate the charges to the companies receiving the 14 services based on cost-causation principles. This basis of cost allocation 15 ensures that the price charged to ETI is no higher than the price charged 16 to other affiliates. 17 18 X. SPONSORED AFFILIATE PRO FORMA ADJUSTMENTS 19 Q. DO YOU SPONSOR ANY OF THE PRO FORMA ADJUSTMENTS TO 20 THE TEST YEAR INCLUDED IN EXHIBIT SBT-12? 21 A. Yes. Exhibit SBT-12 identifies the pro forma adjustments that I sponsor. 2011 ETI Rate Case 9-439 Entergy Texas, Inc. Page 94 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. PLEASE DISCUSS THE PRO FORMA ADJUSTMENTS TO THE TEST 2 YEAR COSTS THAT YOU SPONSOR. 3 A. The adjustments to the test year affiliate costs that I sponsor are listed 4 below. 5 AJ21-04 – PwC Changes in Billing Methods 6 AJ21-11 – Correct Capital Project Codes 7 AJ21-14 – Billing Method Change for Project Code 8 F3PCTDOR01 9 These test year pro forma adjustments are described in greater 10 detail in Exhibit SBT-12 and Exhibit SBT-D, which includes details of the 11 pro forma adjustments by account. 12 13 Q. ARE THERE ANY ADDITIONAL AFFILIATE PRO FORMA 14 ADJUSTMENTS TO THE TEST YEAR THAT ARE SPONSORED BY 15 SOMEONE OTHER THAN YOU? 16 A. Yes. Please refer to Exhibit SBT-12 for a listing and description of the 17 affiliate pro forma adjustments to the test year sponsored by other 18 Company witnesses. 19 20 XI. BENCHMARKING OF ESI COSTS 21 Q. ARE ESI’S COSTS OF PROVIDING ITS SUPPORT SERVICES 22 COMPARABLE TO OTHER SERVICE COMPANIES? 23 A. ESI’s costs are generally in line with those of peer service companies. 2011 ETI Rate Case 9-440 Entergy Texas, Inc. Page 95 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. HAVE YOU DONE ANY TYPE OF ANALYSIS TO REACH THE 2 CONCLUSION THAT ESI’S COSTS ARE GENERALLY IN LINE WITH 3 THOSE OF PEER SERVICE COMPANIES? 4 A. Yes, I conducted a benchmarking analysis comparing ESI’s costs with the 5 costs of peer service companies using publicly available information in the 6 December 31, 2010 FERC Form 60 for a peer group of service companies 7 and the December 31, 2010 Form 10-K for the related holding companies. 8 9 Q. PLEASE DESCRIBE HOW YOU DEVELOPED YOUR LIST OF PEER 10 GROUP SERVICE COMPANIES. 11 A. I identified the list of service companies that submitted a December 31, 12 2010 Form 60 to the FERC. The FERC Form 60 is required to be filed by 13 all utility service companies serving multiple jurisdictions. For 2010, 38 14 service companies, including ESI, submitted the FERC Form 60. Several 15 of these companies have multiple service companies that provide specific 16 services that are not comparable to ESI, including those that provide 17 nuclear generation operations. My analysis excluded those service 18 companies that provide specific services that are not comparable to ESI. 19 In order to ensure direct comparability, my analysis also excluded service 20 companies with a non-U.S. based parent company and companies with 21 fewer than 1 million customers. To ensure that the analysis was 22 performed among similar companies, I then included only those 23 companies whose holding company systems were classified as “Electric 2011 ETI Rate Case 9-441 Entergy Texas, Inc. Page 96 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Utilities” by the Global Industry Classification Standard. Lastly, I excluded 2 those companies whose service company headcount information is not 3 publicly available in the Form 10-K or whose FERC Form 60 does not 4 include service company property. The resulting 2010 ESI peer group 5 used in my benchmarking analysis includes Allegheny, AEP, Exelon, 6 FirstEnergy, Northeast Utilities, PEPCO, and Southern Company. A high 7 level overview of the peer group selection process is included in 8 Exhibit SBT-28A. 9 10 Q. PLEASE DESCRIBE THE FERC FORM 60 DATA AND THE FORM 10-K 11 DATA THAT WAS USED IN YOUR BENCHMARKING ANALYSIS. 12 A. My benchmarking analysis captured service company O&M expense as a 13 percentage of total company O&M, service company O&M expense as a 14 percentage of total company revenue, service company O&M expense as 15 a percentage of total company assets, and service company O&M 16 expense per service company employee. The service company O&M 17 expense is publicly available in the FERC Form 60. The total company 18 O&M, total company revenue, total company assets, and service company 19 headcount are publicly available in the Form 10-K. Cost comparisons 20 were calculated on a per-unit basis rather than a total cost basis due to 21 differing levels of granularity and aggregation in the total costs. 2011 ETI Rate Case 9-442 Entergy Texas, Inc. Page 97 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 Q. WHAT WERE THE RESULTS OF YOUR BENCHMARKING ANALYSIS 2 FOR EACH OF THE COST COMPARISONS LISTED ABOVE? 3 A. As shown in Exhibit SBT-28B, ESI O&M expense represents 21.50% of 4 total company O&M expense, which is below the peer group average of 5 26.33%. As shown in Exhibit SBT-28C, ESI O&M expense represents 6 9.49% of total company revenue, which is below the peer group average 7 of 10.77%. As shown in Exhibit SBT-28D, ESI O&M expense represents 8 1.79% of total company assets, which is below the peer group average of 9 2.05%. Lastly, as shown in Exhibit SBT-28E, ESI O&M expense is 10 $220,325 per ESI employee, which is below the peer group average of 11 $248,142 per service company employee. 12 13 Q. HOW SHOULD COMPARATIVE PERFORMANCE RELATIVE TO A 14 PEER GROUP, AS CALCULATED THROUGH BENCHMARKING, BE 15 VIEWED? 16 A. In general, service company costs that are at or better than average 17 provide an indication that a company is providing services in a cost 18 effective manner. 19 20 Q. WHAT DO YOU CONCLUDE FROM THE BENCHMARKING ANALYSIS 21 THAT YOU PERFORMED? 22 A. The overall benchmarking analysis indicated that ESI performed slightly 23 better than the peer group average. As a result of my benchmarking 2011 ETI Rate Case 9-443 Entergy Texas, Inc. Page 98 of 98 Direct Testimony of Stephanie B. Tumminello 2011 Rate Case 1 analysis, I have concluded that ESI’s costs are generally in line with those 2 of peer service companies, which supports the conclusion that ESI costs 3 charged to ETI are reasonable. 4 5 XII. CONCLUSION 6 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 7 A. Yes, at this time. 2011 ETI Rate Case 9-444 Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 1 of 12 Affiliate Billing Process Controls Overview Several process controls have been established and are in place to help ensure that billings to affiliates represent the actual costs of items or services provided to such affiliates. A brief discussion of each of these controls is provided below. Billing Process Controls – General Multiple Approvals of Project Codes: Multiple approvals by various parties are required for newly initiated project codes. The preparer of a project code (PC) request is responsible for assigning an appropriate billing method(s) to the PC, based on the scope and nature of the work to be performed. The preparer is often the person with the most knowledge about the project and, therefore, is most qualified to choose the appropriate billing method. As a check to make sure the PC has been set up correctly, a minimum of two review points exist. When a new PC is initiated in PowerPlant, the budget coordinator or department manager reviews the PC request. If the PC request is appropriate, then it is routed to the Affiliate Accounting and Allocations (AAA) Outlook inbox for approval. An AAA employee will review the project to ensure that the appropriate billing method is assigned. This is done by reading the scope statement to see what the scope, primary activities, primary products or deliverables, and justification of billing method are for the project. If the scope Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 2 of 12 statement and the billing method chosen are appropriate, then the PC is approved by the AAA employee. If the project code is above a certain dollar amount, then the project will also need manager approval. Depending on the PC, other reviews may also be required to further ensure that the PC is set up correctly. For instance, projects that result in capital expenditures must be reviewed by the Property Accounting department. Once the project code request is approved, the project is ready to receive charges. These charges will proceed through the automated affiliate billing process also known as Service Company Billings. Personnel involved in establishing or reviewing PCs receive training on the selection of an appropriate billing method(s), and on proper procedures for capturing data using project codes. To see the project code set-up in flowchart form, please see Attachment 3 that depicts the process of setting up a billable project code. Approval of Loaned Resource Billing Transactions: Manager approval is required before an employee can initiate a loaned resource transaction involving labor. This ensures that the process is being used correctly and when appropriate. Co-owner Allocation Rules: The co-owner billing process uses allocation rules to capture costs that meet the criteria for co-owner billing. These rules use a combination of FERC account, physical location code, resource code and PC as the criteria for capturing costs Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 3 of 12 to be billed through this process. Co-owner allocation results are reviewed monthly by the allocation owners in the Fuel & Generation Accounting group. Approval of Source Documentation: Prior to the recording of a transaction on the Company’s books, the appropriate personnel must review and approve source documentation (such as timesheets, accounts payable vouchers, and journal entries), in accordance with the requirements of Entergy's approval policies. Budget Process Activities: The budget process also serves as a method of control. Specifically, budget coordinators are directed during budget training to review the project codes used by their departments to ensure that they are appropriate for the services being provided, including the billing method(s) assigned to the project code(s). In addition, the management of each department reviews actual charges on a monthly basis and compares them to budget. This is accomplished through review of the department’s cost reports, which provide actual versus budget comparisons in several ways, e.g., by project, activity, and resource codes. Monthly Allocation Results and Billing Analysis: Reasonableness testing is performed on a monthly basis as a control to ensure the reasonableness of affiliate charges. This process includes reviewing variances within each account. Once a material variance is discovered, it is Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 4 of 12 analyzed and any necessary adjustments are made. Specifically, personnel have the opportunity to identify billing exceptions (not previously identified) through the review, analysis, and reconciliation of variances. If, during the monthly analysis of financial results, a charge by an affiliate to another Business Unit is questioned by management, functional budget coordinators, the Billing Analysis Review Team (BART), or others, then the charges are investigated by Affiliate Accounting and Allocations or another responsible party and handled appropriately. The charge can be traced back to the original entry that created the billing to the company to best analyze the charge. For example, if the analysis of ETI's non-fuel operation and maintenance (“O&M”) expenses indicates that a charge originated from ESI, then the PC generating the billing can be identified. The charges to the PC can then be researched in ESI's general ledger to see what sources initiated the charge and if the charge was billed appropriately. In addition, Affiliate Accounting and Allocations tests the billing results and other allocation results monthly to ensure that project code transactions are billing correctly and allocation results are accurate. Preliminary allocations are run at various times throughout the month in order get a preliminary view of the allocation results before the final allocation run. The final allocation run is always the last business day of the month. Allocation owners are emailed after preliminary allocation runs as a notification and reminder to check preliminary allocation results. Each individual allocation owner will check allocations and notify AAA’s EPM owner of any issues, so that issues can be resolved before the Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 5 of 12 final allocation run. In addition, AAA sends out net income reports during the close period that will identify any PC that didn’t bill out costs. Specifically, these reports indicate the amount of net income, if any, at each service company by PC. AAA employees will analyze the issues and resolve them in a timely manner. Authorization Required to Access Corporate Applications: Another control is the authorization required to access certain software. Employees must be given permission, and must be issued an ID, prior to obtaining access to corporate applications such as PeopleSoft applications, Accounts Payable systems, and Payroll systems. Each user is also often restricted to specific functions within each system relative to his or her requirements and position. Also, these programs are protected by user passwords. These controls help ensure that affiliate costs are properly supported, and no unauthorized changes are made for project billings, loaned resource billings and co-owner billings. Quarterly reviews of system access are required under SOX testing. Billing Process Controls – ESI In addition to the controls discussed above, ESI has the following additional controls: BART Monthly Reviews of ESI Billings: BART was established in 1995 by Affiliate Accounting and Allocations to develop and implement a process to review ESI billings with representatives from each of Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 6 of 12 the regulated companies in order to provide assurance to the Entergy Utility Presidents and jurisdictional regulators that the ESI bill is descriptive and reasonable and that ESI costs are properly allocated. As a result of this team's work, several monthly service billing reports were developed for use as tools to help monitor the cost allocation process on an ongoing basis. One report, listing each Business Unit, also lists each PC charging that Business Unit by PC number, PC description, and billing method utilized. The data is summarized by month and includes a year-to-date total. The second report provides total monthly charges for each PC by Business Unit. Additional reports list all new PCs and PCs with billing method changes during the current month. This report includes PC descriptions, project manager names, and the budgetable and chargeable status of the projects. The BART team is comprised of Affiliate Accounting and Allocations, Regulatory Accounting, Nuclear - Business Services employees, Jurisdictional Finance Directors, Business Analysis Managers and Regulatory Affairs representatives from the operating companies. The BART team has regularly scheduled monthly meetings to review billing results of the preceding month and to discuss billing issues. During the monthly BART meetings, team members review billing results, inquire about specific project billings, and challenge project billing method assignments. Some issues raised during the course of a BART meeting are successfully resolved during the meeting. Unresolved issues are maintained and resolved by AAA after the meeting. The resolution of these issues is later communicated with BART team members. Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 7 of 12 Employee Training: Each ESI employee is ultimately responsible for charging the costs that he or she incurs to the appropriate PC, and thus billing the companies receiving the services appropriately. As a guide, ESI Time and Expense Training materials are posted on the Affiliate Accounting and Allocations section of Entergy’s internal web. All ESI employees are required to acknowledge their review of these training materials on an annual basis via our Corporate Training application, WebTap (Web-based Training Administration Program). This training stresses the importance of choosing the correct PC. It also discusses the role of billing methods in billing the appropriate companies for services rendered, and emphasizes that direct billing is preferred over allocating charges where possible. The training also reviews how to determine which PC should be used for specific services. These ESI Time and Expense Training materials are included in Exhibit SBT-16. Internal Reviews of Affiliate Transactions and Processes Internal Audit reviews the controls and performs tests of transactions and balances related to affiliate billings. Specifically, related to the implementation of the Sarbanes-Oxley Act, Internal Audit reviews the risks, control activities, and testing of those control activities associated with the affiliate billing process. Their review includes the related funding, allocations, intercompany account Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 8 of 12 reconciliations, and access request processes associated with the overall affiliate billing process. External Reviews and Audits of Affiliate Transactions and Processes: There are several reviews or audits of affiliate transactions and processes that occur routinely. For instance, Deloitte & Touche LLP performs certain agreed upon procedures annually at the request of Entergy to satisfy a requirement included in an October 1992 Settlement Agreement, as amended, between certain regulators and Entergy. In connection with the performance of their procedures, Deloitte & Touche LLP selects several intercompany transactions billed to Entergy Enterprises Inc. by Entergy affiliates to ensure that they were billed in accordance with PUHCA 2005 affiliate billing requirements. Deloitte & Touche LLP’s “Independent Accountants’ Report on Applying Agreed-Upon Procedures” for the year ended December 31, 2010 is included in the Attachment 9. In addition, the annual external audit of Entergy Corporation and its subsidiaries’ financial statements performed by Deloitte & Touche LLP helps to detect whether the intercompany accounts and billing processes are producing any material misstatements in the financial statements. The Sarbanes-Oxley Act also requires that an independent auditor attest to the accuracy of the Company’s disclosure regarding the effectiveness of its internal controls. In this connection, D&T also reviews risks, controls activities, and testing of control activities associated with the affiliate billing processes. Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 9 of 12 Further, the FERC, under the authority of the Public Utility Holding Act of 2005, is authorized to periodically conduct audits of service companies. These service company audits include an examination of each service companies’ compliance with cross-subsidization restrictions on affiliate transactions at 18 C.F.R. Part 35, accounting, recordkeeping, and reporting requirements at 18 C.F.R. Part 366, compliance with the Uniform System of Accounts for centralized service companies at 18 C.F.R. Part 367, and preservation of records requirements for service companies at 18 C.F.R. Part 368. During the most recent FERC audit of Entergy’s four service companies, including ESI, covering the period January 2006 through December 2008, the FERC tested for compliance with the aforementioned regulations by conducting tests of the service companies’ cost allocations and the charges billed by the service companies. The FERC reviewed and tested the supporting details for the service companies’ cost allocation methodologies, tested the centralized service companies’ costs and accounting, and reviewed selected service companies’ billings and the corresponding associated franchised public utilities’ accounting for the billings. The FERC letter order dated December 9, 2009 in connection with this audit found there were no significant deficiencies related to the allocation methodologies, accounting, or pricing of service company transactions. Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 10 of 12 Sarbanes-Oxley Controls and Testing: In accordance with Section 404 of the Sarbanes Oxley Act, Entergy is charged with supporting its evaluation of internal controls with sufficient evidence including documentation. Affiliate billings are tested for compliance with Sarbanes Oxley quarterly. AAA keeps documentation current as it relates to processes, risks, controls and test plans, evaluates the effectiveness of internal controls, documents test results in eCART (Entergy’s Compliance and Risk Tool) and actively manages issues. Such tests for internal controls, as they relate to affiliate billings, include Record Payroll Loaders and Payroll Accruals, SAIC Outsourced Billings, Transportation Clearing, Funding and Repayment of Service Billings, Calculate and Record Service Billings, Account Reconciliation Testing, various other allocations, and quarterly reviews of system access. Each process has been evaluated for control risks and each risk has been identified and documented. Testing includes review of process flowcharts and tests for the controls associated with each designated risk. On an annual basis, Internal Audit, accounting personnel, and our external auditors (Deloitte & Touche) evaluate internal controls tests. The external auditors assess the adequacy of documentation in eCART, test and validate the effectiveness of controls, and issue a 404 attestation to the investing community via Entergy’s 10-K. If any deficiencies are reported, immediate steps are taken to resolve issues through the use of the eCART system where an action plan is created. Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 11 of 12 FERC Compliance Controls and Testing In accordance with FERC policies and guidelines, Entergy has established a formal FERC compliance program that identifies risks, control activities, test procedures, and test results for Entergy’s key FERC requirements. Similar to Sarbanes-Oxley controls and testing, Entergy maintains the documentation for these requirements, risks, control activities, test procedures, test results, and any related issues in eCART. The tests of FERC control activities, as they relate to affiliate billings, include testing related to FERC pricing requirements as set forth under FERC Order Nos. 707 and 707-A, which became effective as of March 31, 2008. These orders include asymmetrical pricing requirements for transactions between franchised public utilities and their non-utility affiliates. The control activities related to FERC pricing requirements are tested on a quarterly basis to ensure compliance with the FERC requirements. In addition, Entergy reports the methods of allocation in the annual FERC Form 60 filed by each of its service companies. The related FERC Form 60 schedule indicates the service department or function and the basis for the allocation used when employees render services to more than one department or functional group. Further, new methods of allocation are submitted to the FERC for review and acceptance prior to implementation. Affiliate Transactions Policy The Entergy System Accounting Policy entitled “Affiliate Transactions” is posted on Entergy’s internal web. This policy is maintained by the Affiliate Accounting Exhibit SBT-15 2011 TX Rate Case Attachment 8 Page 12 of 12 and Allocations group and sets forth the standards for affiliate transactions related to affiliate controls and pricing. This policy is reviewed annually and updated as necessary. Summary The use of project codes and cost-causative allocation factors filed with the FERC, as well as the internal review of charges among all affiliates, including ETI, help to ensure that all affiliates bear only those charges for services each receives. Each of the controls discussed above is an integral part of a multi- faceted process that is designed to bill the appropriate share of reasonable and necessary charges to the affiliates. Entergy Services, Inc. Exhibit SBT-26 Net Book Value of Assets 2011 TX Rate Case Page 1 of 1 As of June 30, 2011 Plant Accumulated Life Asset Description Plant In Service Net Plant Account Depreciation (Months) 303 Externally Purchased Software Systems $45,299,093 $32,159,946 $13,139,146 60/120 303 Internally Developed Software Systems 47,545,691 28,356,365 19,189,326 60/120 303 Misc. Computer Software 23,033,402 15,931,317 7,102,084 60/120 3891 Land 2,212,516 0 2,212,516 N/A 390 Capital Lease - Structures 32,137,871 3,079,879 29,057,992 LED* 390 Leasehold Improvements 33,841,914 17,220,908 16,621,007 LED* 390 Owned Buildings 39,717,801 4,466,429 35,251,372 378 3911 Furniture & Fixtures 10,840,746 5,702,565 5,138,181 120 3912 Computer Equipment 67,201,729 44,457,299 22,744,431 60 3913 Data Handling Equipment 402,506 189,154 213,352 120 392 Transportation - Auto 1,903 1,903 0 60 392 Transportation - Cessna 83,558,696 7,658,629 75,900,068 120 392 Transportation - Falcon 23,843,613 6,868,734 16,974,879 120 392 Transportation - Other 67,891 34,927 32,964 60 395 Laboratory Equipment 68,333 7,694 60,639 60 3971 Fiber Optic Equipment 3,975,059 2,089,724 1,885,335 120 3971 Microwave Equipment 2,570,585 2,570,585 0 120 3971 Other Communication Equipment 19,529,933 10,220,235 9,309,698 60/120 398 Miscellaneous Equipment 10,330,439 5,414,646 4,915,794 120/180 Total $446,179,722 $186,430,939 $259,748,783 * LED = Lease End Date. Leasehold improvements are depreciated using the straight-line depreciation method. The number of months used to depreciate the improvements are generally the months between the creation of the asset and the end of the lease. Exhibit SBT-26 2011 TX Rate Case Amounts may not add or tie to other schedules due to rounding. Page 1 of 1 WP/SBT-4 2011 TX Rate Case Page 1 of 7 Entergy Texas, Inc. Summary of Costs Billed by Entergy Services, Inc. and Other Entergy Affiliates to Entergy Texas, Inc. for the year ended June 30, 2011 Entergy Texas, Inc. WP/SBT-4 2011 TX Rate Case Index Page 2 of 7 For the year ended June 30, 2011 Page(s) Report of Independent Accountants ............................................................................................................ 1 Management’s Assertion Regarding the Summary of Costs Billed by Entergy Services, Inc. and Other Entergy Affiliates to Entergy Texas, Inc. ............................................................................................ 2 Summary of Costs Billed by Entergy Services, Inc. and Other Entergy Affiliates to Entergy Texas, Inc. ............................................................................................ 3 Notes to Summary of Costs Billed by Entergy Services, Inc. and Other Entergy Affiliates to Entergy Texas, Inc. ......................................................................................... 4-5 WP/SBT-4 2011 TX Rate Case Page 3 of 7 Report of Independent Accountants To the Management of Entergy Services, Inc. We have examined management’s assertion, included in the accompanying Management’s Assertion Regarding the Summary of Costs Billed by Entergy Services, Inc. (“ESI”) and Other Entergy Affiliates to Entergy Texas, Inc. (“ETI”), that the Summary of Costs Billed by Entergy Services, Inc. and Other Entergy Affiliates to Entergy Texas, Inc. for the year ended June 30, 2011 (“Summary of Costs Billed”), is an accurate presentation of costs billed to ETI based on the criteria set forth in management’s assertion as further described by the Notes to the Summary of Costs Billed. ESI’s management is responsible for the assertion. Our responsibility is to express an opinion based on our examination. Our examination was conducted in accordance with attestation standards established by the American Institute of Certified Public Accountants and, accordingly, included examining, on a test basis, evidence supporting management’s assertion and performing such other procedures as we considered necessary in the circumstances. We believe that our examination provides a reasonable basis for our opinion. In our opinion, management’s assertion referred to above is fairly stated, in all material respects, based on the criteria set forth in management’s assertion, as further described in the Notes to the Summary of Costs Billed. This report is intended solely for the information and use of Duggins Wren Mann & Romero, LLP, ETI, ESI and the Texas Public Utility Commission, and is not intended to be and should not be used by anyone other than these specified parties. October 31, 2011 PricewaterhouseCoopers LLP, 639 Loyola Avenue, Suite 1800, New Orleans, LA 70113 T: (504) 558 8200, F: (504) 558 8960, www.pwc.com/us WP/SBT-4 2011 TX Rate Case Page 4 of 7 Management’s Assertion Regarding the Summary of Costs Billed by Entergy Services, Inc. and Other Entergy Affiliates to Entergy Texas, Inc. Management of Entergy Services, Inc. has prepared the accompanying Summary of Costs Billed by Entergy Services, Inc. (“ESI”) and Other Entergy Affiliates to Entergy Texas, Inc. (“ETI”) for the year ended June 30, 2011 (“Summary of Costs Billed”). The Summary of Costs Billed includes only amounts recognized as expense by ETI and does not include any costs charged to project codes used for capital projects. Management asserts that the Summary of Costs Billed is an accurate presentation of costs billed to ETI based on the criteria set forth below. ESI has established systems and processes to accumulate costs and bill them on a cost causative basis to affiliates, including ETI. The billing methods used to bill costs ensure that costs billed to ETI reasonably approximate the actual costs of services provided and are no higher than the costs billed to other affiliates for similar services. In addition to the ESI costs billed to ETI, other Entergy affiliates have directly billed ETI for loaned resources or co-owner billings. For purposes of this assertion, management has defined the accurate presentation of costs billed to ETI as inclusion of only costs (i) charged to a project code related to a project scope statement filed as part of the rate case and subsequently billed to ETI based on the billing method in the respective project code or (ii) other affiliate costs directly charged to ETI as further described in the Notes to the Summary of Costs Billed by Entergy Services, Inc. and Other Entergy Affiliates to Entergy Texas, Inc. Entergy Texas, Inc. WP/SBT-4 2011 TX Rate Case Summary of Costs Billed by Entergy Services, Inc. and Page 5 of 7 Other Entergy Affiliates to Entergy Texas, Inc. For the year ended June 30, 2011 (dollars in thousands) Final Costs Billed $78,998,777 The Notes to Summary of Costs Billed by Entergy Services, Inc. and Other Entergy Affiliates to Entergy Texas, Inc. for the year ended June 30, 2011 are an integral part of this summary 3 Entergy Texas, Inc. WP/SBT-4 2011 TX Rate Case Notes to the Summary of Costs Billed by Entergy Services, Inc. and Page 6 of 7 Other Entergy Affiliates to Entergy Texas, Inc. For the year ended June 30, 2011 1. Background Entergy Texas, Inc. (“ETI” or the “Company”) is a wholly-owned subsidiary of Entergy Corporation (“Entergy”). Entergy Corporation and Subsidiaries is an integrated energy company engaged primarily in electric power production and the operation of a retail electric distribution system (the “Entergy System” or “System”). Through a series of wholly-owned subsidiaries, Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity and delivers electricity to 2.7 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. ETI is one of Entergy Corporation’s integrated utility companies serving customers in Texas. Entergy Services, Inc. (“ESI”), a corporation wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services to ETI, as well as other Entergy subsidiaries. ESI provides its services to ETI on an “at cost” basis, determined using billing methods based on cost causative factors (for example, total assets, number of customers, payroll checks, IT spending, insurance premiums, server / mainframe usage, number of personal computers, accounts payable and receivable metrics, number of employees, general ledger transactions, distribution and transmission line mileage, distribution and transmission substations, generating capacity, generating capability, and customer load ) pursuant to service agreements that were previously approved by the Securities and Exchange Commission (“SEC”) under PUHCA 1935 and those subsequently accepted by the Federal Energy Regulatory Commission (“FERC”) following adoption of PUHCA 2005. ETI maintains its accounting books and records in accordance with FERC and other regulatory guidelines, as well as in accordance with accounting principles generally accepted in the United States (GAAP). 2. Costs Billed by ESI and Other Entergy Affiliates ESI's costs incurred in providing services to ETI and other Entergy affiliates are set forth in the service agreements and include, but are not limited to, labor and related overhead costs (e.g., salaries of officers and other employees, employee welfare expenses such as social security taxes, life insurance, pensions, post-retirement benefits other than pension, medical, dental and other welfare expenses), training costs, facilities costs, information technology costs and costs related to vendor and other contract services. ESI has established systems and processes to accumulate costs and bill them on a cost causative basis to affiliates, including ETI. The key objectives of these systems and processes are to ensure that: Charges to affiliates reasonably approximate the cost of services provided, Prices charged to and paid by each affiliate are no higher than the prices charged to and paid by other affiliates for similar services, Cost causative correlation exists between the services provided and the affiliates receiving the services, and Billing methods used to bill costs ensure accurate recording and billing of the costs associated with the provision of the related services. 4 Entergy Texas, Inc. WP/SBT-4 2011 TX Rate Case Notes to the Summary of Costs Billed by Entergy Services, Inc. and Page 7 of 7 Other Entergy Affiliates to Entergy Texas, Inc. For the year ended June 30, 2011 To achieve these objectives, ESI accumulates its actual costs incurred in project codes. The project codes function as the primary cost control element from which costs are billed to the affiliates. For each project code, a project scope statement documents a description of the project code’s use and purpose, the activities associated with that particular project, the expected deliverables from activities in the project, and justification for the billing methodology to be used for billing the costs accumulated in the project. Only one ESI billing methodology may be used for each project code to bill ESI costs to Entergy’s legal entities (including ETI). ESI charges no more than actual costs for services provided to ETI and other regulated affiliates. The monthly billing process includes only the costs accumulated in the project codes. There is no markup or profit included in billings to the regulated companies. The billings are based on the billing methodologies designated and described above. Accordingly, the unit cost (price) charged to these affiliates, including ETI, is intended to reasonably approximate the actual costs of providing such services. Entergy affiliates other than ESI also have the ability to bill ETI through the use of loaned resources and co-ownership transactions. In these cases, services are provided directly to ETI and as such are billed 100% to ETI. 3. Billing Adjustments ESI completed an analysis of project codes and related billing methods in connection with the preparation of the Summary of Costs Billed for the year ended June 30, 2011. Final Costs Billed in the Summary of Costs Billed includes additional expenses of $7,368, which increase the amounts originally billed to ETI during the year ended June 30, 2011. 5 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 ETI 2011 Rate Case ETI EXHIBIT NO. 50 SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 APPLICATION OF ENTERGY § TEXAS, INC. FOR AUTHORITY TO § BEFORE THE CHANGE RATES, RECONCILE § STATE OFFICE OF FUEL COSTS, AND OBTAIN § ADMINISTRATIVE HEARINGS DEFERRED ACCOUNTING § TREATMENT § REBUTTAL TESTIMONY OF KEVIN G. GARDNER ON BEHALF OF ENTERGY TEXAS, INC. APRIL 2012 1 ENTERGY TEXAS, INC. REBUTTAL TESTIMONY OF KEVIN G. GARDNER PUC DOCKET NO. 39896 TABLE OF CONTENTS Page I. Introduction 1 II. Incentive Compensation 2 III. Allegations Regarding Base Pay and Benefits Levels 10 IV. Supplemental Executive Retirement Benefits Plans 14 V. Relocation Costs 17 2 Entergy Texas, Inc. Page 1 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 I. INTRODUCTION 2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 3 A. My name is Kevin G. Gardner. My business address is 639 Loyola 4 Avenue, New Orleans, Louisiana 70113. 5 6 Q. DID YOU PREVIOUSLY FILE DIRECT TESTIMONY ON BEHALF OF 7 ENTERGY TEXAS, INC. (“ETI” OR “THE COMPANY”) IN THIS 8 PROCEEDING? 9 A. Yes, I did. 10 11 Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY? 12 A. The purpose of my rebuttal testimony is to address issues raised in the 13 Direct Testimonies of Public Utility Commission of Texas (“Commission” or 14 “PUCT”) Staff witness Anna Givens, Cities witness Mark Garrett, and 15 Texas Industrial Energy Consumers (“TIEC”) witness Jeffry Pollock 16 regarding ETI’s requested recovery of its incentive compensation costs. I 17 also address Mr. Garrett’s recommendations to disallow amounts 18 associated with allegedly above-market base pay and employee benefits. 19 Finally, I address the recommendations of Mr. Garrett and Office of Public 20 Utility Counsel (“OPUC”) witness Carol Szerszen to disallow the 21 supplemental retirement benefits costs included in ETI’s cost of service. 3 Entergy Texas, Inc. Page 2 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 II. INCENTIVE COMPENSATION 2 Q. DO YOU HAVE ANY OVERALL OBSERVATIONS ON THE PROPOSED 3 TREATMENT OF THE COMPANY’S INCENTIVE COMPENSATION BY 4 OTHER PARTIES? 5 A. Yes. The Staff, Cities, and TIEC propose significant disallowances for the 6 Company’s incentive compensation programs. In some instances, their 7 recommendations exceed the treatment of these types of costs in prior 8 PUCT proceedings. The Company’s incentive programs play an important 9 role in serving ETI’s customers. Primarily, the Company’s incentive 10 programs achieve the following indispensable goals: 11 1. Allow the Company to attract and retain reliable, experienced, and 12 highly trained employees who ensure that ETI provides safe and 13 reliable electric service to our customers. 14 2. Maintain compensation within reasonable market levels by 15 establishing a balanced portfolio of “at risk” incentives to be paid 16 only when established customer-focused goals are met. 17 3. Ensure “at risk” compensation is only delivered when performance 18 goals are met and allow the Company’s total compensation costs to 19 be more directly tied to performance. 20 4. Create safety, operational, customer, and cost control goals that 21 help establish a clear line of sight between employees and the 22 customers they serve. 4 Entergy Texas, Inc. Page 3 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 For these reasons and as detailed in my direct testimony, the 2 Commission should further evaluate its stance in general on incentive 3 compensation. The Company has attempted to resolve many of the 4 concerns raised in those prior proceedings by changing the annual 5 incentive program for the majority of employees to be even more customer 6 focused. This “line of sight” between employees and current annual 7 incentive goals, which focus on safety, operational, and cost control, 8 provide an increased benefit to its customers. My direct testimony and 9 that of Company witness Dr. Jay Hartzell explained these changes and 10 provided additional evidence on the customer benefits of all incentive 11 compensation. 12 13 Q. PLEASE SUMMARIZE STAFF AND INTERVENOR WITNESS 14 RECOMMENDATIONS FOR ETI’S INCENTIVE COMPENSATION 15 COSTS. 16 A. In her pages 15-22, Staff witness Givens recommends that portions of the 17 annual and long-term incentive compensation costs tied to financial goals 18 should be disallowed. She calculates a total of $5,609,093 in such costs. 19 As summarized on his page 45, TIEC witness Pollock recommends 20 a $6.2 million disallowance for costs related to annual and long-term 21 incentive compensation plan goals that are tied to financial measures. 22 Mr. Pollock bases his proposed disallowance on Commission precedent of 23 disallowing incentive compensation based on financial measures. 5 Entergy Texas, Inc. Page 4 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 As detailed in Table 3 on his page 49, Cities witness Garrett 2 recommends removing 100% of ETI’s costs related to the Company’s 3 long-term incentive compensation because all of these programs are tied 4 to “financial” goals. He also recommends removing 35% of the costs of 5 each of the Company’s annual incentive plans based on his determination 6 that 35% of the goals used in these plans are “financial” in nature. 7 Further, he recommends on his pages 52-53 that the pro forma rate base 8 should be decreased by $9,835,111 for capitalized annual and long-term 9 incentive compensation costs going back as far as January 2008 related 10 to “financial” goals. Finally, Mr. Garrett asserts on his pages 50-51 that 11 the Commission might consider disallowing all of ETI’s incentive 12 compensation costs because the Company uses the Entergy Achievement 13 Multiplier (“EAM”) as a funding mechanism as part of its annual incentive 14 compensation plans. 15 16 Q. DO YOU AGREE THAT INCENTIVE COMPENSATION COSTS 17 RELATED TO FINANCIAL GOALS SUCH AS PROFITIBILITY AND 18 STOCK PRICE SHOULD BE DISALLOWED BY THE COMMISSION? 19 A. No. The Company should be able to recover its financially related 20 incentive compensation costs because (1) customers benefit from these 21 costs and goals, (2) such costs are a necessary business expense, and 22 (3) the Company’s level of such costs was reasonable. Because they are 23 necessary, reasonable, and benefit customers, the Company’s financially 6 Entergy Texas, Inc. Page 5 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 related incentive compensation costs should be recoverable whether such 2 costs are related to the Company’s annual incentive plans, long-term 3 incentive plans, or the Company’s capital costs. 4 5 Q. HOW DO CUSTOMERS BENEFIT FROM FINANCIALLY BASED GOALS 6 SUCH AS PROFITIBILITY AND STOCK PRICE? 7 A. Having incentive compensation related to financial goals is standard for 8 companies such the Entergy Companies, and the Entergy Companies 9 must offer competitive incentive compensation programs in order to 10 compete and retain talented employees. Customers benefit from a utility 11 that attracts and retains qualified personnel. Further, having only 12 operational and safety goals in the incentive compensation plans could 13 encourage utility personnel to overspend in some areas and would result 14 in an unbalanced incentive compensation program. Customers benefit by 15 having the utility personnel balance the operational/safety goals with 16 financial goals. The direct testimony of Company witness Hartzell 17 identifies other important benefits to customers. 7 Entergy Texas, Inc. Page 6 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 Q. ON HIS PAGES 47-48, MR. GARRETT RECOMMENDS 2 DISALLOWANCE OF ALL INCENTIVE COMPENSATION EXPENSES 3 THAT ARE BASED ON COST CONTROL MEASURES. DO YOU 4 AGREE WITH THIS RECOMMENDATION? 5 A. No, rejecting incentive compensation linked to cost control measures is 6 short-sighted and ignores the benefits to customers that result from these 7 measures. It is difficult to accept that the Commission would penalize a 8 utility’s efforts to foster cost control as a goal. Neither TIEC witness 9 Pollock nor Staff witness Givens seeks to disallow incentive costs tied to 10 cost control measures. Mr. Garrett even admits on his page 31, line 6 that 11 incentive plans that motivate employees to achieve increased cost control 12 efficiencies should be encouraged. The Commission should encourage 13 cost control efficiencies by allowing the Company to recover its incentive 14 compensation costs related to cost control goals. 15 16 Q. PLEASE EXPLAIN THE NATURE OF THE COST CONTROL 17 MEASURES AND HOW CUSTOMERS BENEFIT FROM THOSE GOALS. 18 A. The Entergy Companies’ cost control goals focus on the customer by 19 encouraging increased productivity and improved efficiencies in 20 operational performance. Almost every business, non-profit organization, 21 governmental agency, and household uses a budget as a tool to meet its 22 cost control objectives. Customers benefit from cost control goals in 23 multiple ways: 8 Entergy Texas, Inc. Page 7 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 When the cost control efforts affect fuel, purchased power 2 energy, and energy efficiency costs, customers are directly 3 benefited through the periodic adjustment of the rates that 4 recover these costs and the Commission-prescribed 5 reconciliations of those costs. 6 When the cost control efforts relate to capital projects, 7 customers are directly benefitted when those costs are 8 incorporated into the utility’s rate base. 9 When cost control measures relate to other O&M costs during a 10 test year, customers are directly benefitted in the rates set 11 based upon that test year’s costs. 12 Cost controls measures related to non-test-year O&M costs 13 directly benefit customers because savings achieved in a 14 particular year often carry over for several years, any one of 15 which may be a test year. 16 To exclude annual incentive costs based on cost control measures 17 because of a difference in the timing of when a portion of these efforts 18 may benefit shareholders versus customers is an extreme position that 19 should be rejected. To the contrary, creating an environment where cost 20 control by employees is encouraged every year is exactly what utilities 21 should be doing. 22 Further, the operational focus of cost control is directly linked to the 23 customer. This is one reason why the Company has a major focus on 9 Entergy Texas, Inc. Page 8 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 continuous improvement. This continuous improvement model energizes 2 the workforce to continually look for better ways to run the business more 3 efficiently, which results in lower costs and customer bills. Our 4 employees’ focus is directed on the customer, not the shareholder, as the 5 beneficiary of their cost savings, improved efficiencies, and process 6 improvements. 7 8 Q. PLEASE DESCRIBE HOW THE CONTINOUS IMPROVEMENT MODEL 9 IS IMPLEMENTED AT ETI AND HOW IT TIES COST CONTROL TO 10 CUSTOMER INTEREST. 11 A. Entergy’s continuous improvement model encourages employees to look 12 at their daily activities and implement changes to streamline processes 13 and eliminate unnecessary processes. The intent is that these improved 14 activities will result in increased productivity and efficiencies that will 15 ultimately benefit our customers. 16 17 Q. ON PAGE 39, MR. GARRETT PURPORTS TO EXPLAIN THE 18 IMPORTANCE OF THE DISTINCTION BETWEEN FINANCIAL 19 PERFORMANCE MEASURES AND OPERATIONAL MEASURES. DO 20 YOU AGREE WITH HIS ANALYSIS? 21 A. No. In terms of their benefit to customers, I firmly disagree with the 22 position that there is a meaningful distinction between “financial” 23 performance incentive targets and “operational” incentive performance 10 Entergy Texas, Inc. Page 9 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 targets. The earnings or net income encouraged by financial targets are 2 specifically and directly the product of employee efforts to control or 3 manage costs, operate efficiently and improve efficiency, and to provide 4 strong customer service. Improved earnings are achieved by better 5 margins — i.e., more efficient operations, by improved performance and 6 cost management. The critical goal of incentives is to obtain these 7 improved margins without sacrificing quality of service. That is what a 8 balanced incentive program achieves. 9 10 Q. WHAT DOES MR. GARRETT RECOMMEND IN HIS ANALYSIS OF THE 11 EAM AND THE ANNUAL INCENTIVE PLANS? 12 A. On his pages 50-51, Mr. Garrett’s relies on the use of the EAM as the 13 basis for the possible disallowance of all annual incentive payments. 14 15 Q. IS IT REASONABLE TO DISALLOW INCENTIVE COMPENSATION 16 COSTS BECAUSE THE OVERALL FUNDING MECHANISM (THE EAM) 17 IS FINANCIAL IN NATURE? 18 A. No. It only makes common sense, from the Company’s and customers’ 19 perspective, to ensure that the Company is able to afford to pay out the 20 annual incentive payments before it does so. Funding mechanisms within 21 incentive plans such as the EAM simply support the Company’s financial 22 capacity to pay for operational performance-based programs. The 23 benefits that the ratepayers receive from the operational-based goals in 11 Entergy Texas, Inc. Page 10 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 the incentive compensation plans are in no way diminished by the fact that 2 the Company requires a funding mechanism to ensure its capability to pay 3 out incentives. 4 Lack of prudent financial controls would not be in the best interest 5 of the Company’s customers, employees, or shareholders. All companies, 6 whether categorized as regulated utilities or general industries, must 7 employ sound financial management. 8 9 Q. DO YOU AGREE WITH MR. GARRETT’S STATEMENTS ON HIS 10 PAGES 49-50 AND 52 THAT AN EVEN LARGER DISALLOWANCE OF 11 INCENTIVE COMPENSATION COSTS MAY BE MERITED BY THE 12 COMPANY’S LEVELS OF CUSTOMER SATISFACTION? 13 A. No, as explained in the rebuttal testimony of Company witness 14 Vernon Pierce, the facts support the exact opposite result. 15 16 III. ALLEGATIONS REGARDING BASE PAY AND BENEFITS LEVELS 17 Q. PLEASE DESCRIBE THE TESTIMONY OF MR. GARRETT REGARDING 18 ABOVE-MARKET BASE PAY. 19 A. On his pages 25-27, Mr. Garrett alleges that the Company’s base pay 20 levels are 2% above market. He then asserts that ratepayers should only 21 be asked to pay the necessary market-based price for employee pay, and 22 he recommends a 2% downward adjustment to base pay costs to “bring 23 the Company’s base pay down to a market-based level.” 12 Entergy Texas, Inc. Page 11 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 Q. DO YOU AGREE WITH HIS ALLEGATIONS AND RECOMMENDATION? 2 A. No. The Company’s base pay is not 2% above market. The Company’s 3 test year base pay was 2% above market median. For the reasons 4 explained below, being “at market” means being within a reasonable 5 range, such as +/-10%, of the market median; therefore, the Company’s 6 base pay levels are at market.1 7 As indicated in my direct testimony, the Entergy Companies have 8 established a pay philosophy that is competitive with the market. The 9 Entergy Companies focus wages on a reasonable range around the 10 50th percentile of the market. That is the point at which half the companies 11 in the surveys pay total annual compensation that exceeds the market's 12 total annual compensation midpoint and half the companies in the surveys 13 pay less than the market's total annual compensation midpoint. The 14 Entergy Companies consider this to be a competitive but reasonable pay 15 philosophy. 16 To obtain market data, the Entergy Companies participate in well- 17 established and highly-regarded surveys from providers such as Towers 18 Watson, Mercer and AON Hewitt (formerly, Hewitt Associates). However, 19 no two jobs, even within the same organization, are likely to be identical, 20 much less between organizations. There are many jobs that cannot be 21 matched at all and must be slotted internally. The details of the survey 1 Further, as I indicated on page 23 of my direct testimony, some compensation consultants would even use a +/- 15 percent range for pay levels. At this point, the Entergy Companies continue to target +/- 10 percent in establishing compensation levels. 13 Entergy Texas, Inc. Page 12 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 data can vary among participating organizations. As a result, 2 benchmarking jobs to the market is an inexact science. 3 Although benchmarking has its place in compensation analyses, 4 and is commonly used by HR departments and professionals, there are 5 differences in how companies match job responsibilities with job titles and 6 in how companies complete the compensation survey information. These 7 limitations do not invalidate benchmark comparisons of compensation 8 levels, but they do add an element of imprecision to any comparison of 9 compensation by job title. 10 With this in mind, when using a benchmark analysis to compare 11 companies' levels of compensation, it is advisable to view the market level 12 of compensation as a range (e.g., +/- 10% of a mid-point) rather than a 13 precise, single point. Market data for numerous positions move from year 14 to year, so the Entergy Companies see annual compensation of +/-10% of 15 market median as both a reasonable and necessary expense to provide 16 service to the public. This approach is not just an Entergy Companies' 17 point of view, but one commonly used by compensation consultants. 14 Entergy Texas, Inc. Page 13 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 Q. PLEASE DESCRIBE THE ALLEGATIONS OF MR. GARRETT 2 REGARDING ABOVE-MARKET BENEFITS. 3 A. On his pages 58-59, Mr. Garrett states that the value of the Company’s 4 employment benefit plans is 14% above market when compared to a peer 5 group of Fortune 500 companies. He then asserts that ratepayers should 6 only be asked to pay the market-based price for employee costs, and 7 recommends a 14% downward adjustment to the Company’s employee 8 benefits expense. 9 10 Q. DO YOU AGREE WITH MR. GARRETT’S ALLEGATIONS AND 11 RECOMMENDATION? 12 A. No. The value of the Company’s benefits plans is not 14% above market. 13 Table 6 on page 42 of my direct testimony shows that the value of the 14 Entergy Companies’ benefits plans is only 1% above the market median of 15 the peer group of utility companies. As noted with regard to base pay, 16 being “at market” means being within 10% of the market median; therefore 17 the Company’s benefits levels are at market with regard to its peer group 18 of utility companies.2 Even if one gives equal weight to the reported 19 benefits plan values of the Fortune 500 companies and the peer utilities, 20 the value of the Company’s benefit plans is at market. Moreover, the peer 21 group of utility companies provides a more appropriate comparison for the 22 Company’s benefits plans because utilities often need to attract more 2 Nowhere did I purport to identify a “peer group of Fortune 500 companies.” 15 Entergy Texas, Inc. Page 14 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 long-term employees than Fortune 500 companies, such as the nation’s 2 large retail companies. Experienced, long-term employees are needed to 3 operate and manage the utility infrastructure. Employee retention is thus 4 a particularly important issue for utilities, and benefits plans play an 5 important role in achieving strong retention rates. Accordingly, the 6 Company’s benefit plan levels are well within a reasonable range, and no 7 disallowance should be required. 8 9 IV. SUPPLEMENTAL EXECUTIVE RETIREMENT BENEFITS PLANS 10 Q. PLEASE DESCRIBE THE ISSUE RAISED BY THE STAFF, CITIES AND 11 OPUC WITNESSES REGARDING SUPPLEMENTAL EXECUTIVE 12 RETIREMENT PLANS. 13 A. The Company provides three types of supplemental executive retirement 14 plans that are addressed by Staff witness Givens, Cities witness Garrett 15 and OPUC witness Szerszen. The plans include the Pension Equalization 16 Plan, the Supplemental Retirement Plan, and the System Executive 17 Retirement Plan. The plans are further described in Schedule G-2 to the 18 Company’s Rate Filing Package. Ms. Givens recommends, on her pages 19 22-23, and Mr. Garrett recommends, on his page 55, a disallowance of 20 both ETI and ESI-billed costs for these programs, quantifying the total 21 amount as $2,114,931.3 Dr. Szerszen recommends a disallowance of the 3 Company witness Tumminello identifies $112,531 of these ESI costs that should not have been charged to ETI. 16 Entergy Texas, Inc. Page 15 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 portion of these costs allocated from ESI to ETI, which she quantifies at 2 $1,391,861.4 Mr. Garrett argues that these costs are not necessary to 3 provide utility service but are instead discretionary payments that should 4 be funded by shareholders. Dr. Szerszen contends that ETI has not 5 shown that these costs are necessary to provide utility service, and that 6 the ESI allocation method is unjustified. Ms. Givens describes the 7 payments as excessive. I disagree with each of these contentions. 8 9 Q. WHY ARE THE COSTS OF THESE PLANS REASONABLE AND 10 NECESSARY? 11 A. Supplemental executive retirement plans are established for the purpose 12 of attracting, retaining, and motivating highly competent and qualified 13 leaders. In particular, the Pension Equalization Plan provides 14 supplemental retirement benefits to account for the fact that Internal 15 Revenue Code regulations limit the level of retirement benefits that qualify 16 for tax treatment favorable to ETI and Entergy Corporation. The existence 17 of this supplemental benefit program allows the Company to pay 18 retirement benefits to these employees that are proportionate to the 19 compensation they receive while active in their employment. 20 In addition, the Supplemental Retirement Plan and the System 21 Executive Retirement Plan provide supplemental benefits beyond the 4 Company witness Tumminello identifies $112,531 of these costs that should not have been charged to ETI. 17 Entergy Texas, Inc. Page 16 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 amounts restricted in the qualified plan to some participants to attract, 2 retain, and motivate employees. 3 These retirement benefits are widely provided by companies within 4 the utility business sector. Accordingly, ETI needs to offer them in order to 5 be competitive in the employment market with peer companies, and 6 thereby to retain and adequately compensate these employees in terms of 7 future retirement benefits. For these reasons, I conclude that the costs to 8 ETI of these plans are reasonable and necessary. 9 10 Q. OPUC WITNESS SZERSZEN SUGGESTS THAT AN ADDITIONAL 11 REASON TO DENY RECOVERY OF ESI AFFILIATE CHARGES FOR 12 SUPPLEMENTAL RETIREMENT BENEFITS IS THAT THERE IS NO 13 CAUSAL RELATIONSHIP BETWEEN THESE TYPES OF COSTS AND 14 THE ALLOCATION METHOD USED TO BILL ETI ITS SHARE. WHICH 15 COMPANY WITNESSES ADDRESSES THIS ISSUE? 16 A. Company witness Stephanie B. Tumminello addresses this issue. 18 Entergy Texas, Inc. Page 17 of 18 Rebuttal Testimony of Kevin G. Gardner Docket No. 39896 1 V. RELOCATION COSTS 2 Q. WHAT IS MS. GIVENS’ POSITION ON EMPLOYEE RELOCATION 3 ASSISTANCE, AND DO YOU AGREE WITH HER 4 RECOMMENDATION? 5 A. On her page 24, Staff witness Givens recommends that this type of 6 expense be disallowed based on their removal from cost of service in 7 Lower Colorado River Authority Docket No. 28906 and the level of 8 ETI’s annual compensation. I disagree with her recommendation. 9 Finding of Fact No. 86 in the Commission’s final order in Docket 10 No. 28906 states that “LCRA’s wages are competitive, thus a bonus or 11 moving allowance is not necessary to attract quality personnel.” For 12 the employee market in which ETI operates, however, most peer 13 companies offer moving assistance. Such assistance is expected by 14 employees, and the Company would be placed at a competitive 15 disadvantage if it did not offer it. 16 Further, though Ms. Givens points to the Company’s level of 17 annual compensation as a basis for disallowing this benefit cost, she 18 sought to disallow no other benefits costs. Just as the Company’s level 19 of compensation does not merit disallowing medical and dental benefits 20 costs, it does not merit disallowing relocation cost benefits if the level of 21 such costs is reasonable. Ms. Givens does not dispute the 22 reasonableness of the amount. In fact, as I indicated by my direct 19 Entergy Texas, Inc. Page 18 of 18 Rebuttal Testimony of Kevin G. Gardner Revised – Errata No. 7 Docket No. 39896 1 testimony on page 46, the Entergy Companies’ average relocation 2 assistance amounts during the test year were reasonable when 3 compared to 2010 industry average relocation costs as reported by the 4 Employee Relocation Council. Recovery of this expense should be 5 authorized.1 6 7 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY? 8 A. Yes. 1 Staff witness Givens also recommends a disallowance related to certain executive perquisites; the Company is not opposing that adjustment. SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 ETI 2011 Rate Case ETI EXHIBIT NO. 53 SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 APPLICATION OF ENTERGY § TEXAS, INC. FOR AUTHORITY TO § BEFORE THE CHANGE RATES, RECONCILE § STATE OFFICE OF FUEL COSTS, AND OBTAIN § ADMINISTRATIVE HEARINGS DEFERRED ACCOUNTING § TREATMENT § REBUTTAL TESTIMONY OF JAY C. HARTZELL, Ph.D. ON BEHALF OF ENTERGY TEXAS, INC. APRIL 2012 1 ENTERGY TEXAS, INC. REBUTTAL TESTIMONY OF JAY C. HARTZELL, Ph.D. DOCKET NO. 39896 TABLE OF CONTENTS Page I. Introduction and Qualifications 1 II. Purpose of Rebuttal Testimony 1 III. Response to Mr. Garrett’s Policy Arguments Opposing Inclusion of “Financially” Related Incentive Compensation in Rates 2 IV. Response to Mr. Pollock’s and Ms. Givens' Policy Arguments Opposing Inclusion of “Financially” Related Incentive Compensation in Rates 13 V. Conclusion 15 2 Entergy Texas, Inc. Page 1 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 I. INTRODUCTION AND QUALIFICATIONS 2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 3 A. My name is Jay C. Hartzell. I am the Chair of the Finance Department, 4 Professor of Finance, and the Allied Bancshares Centennial Fellow at the 5 McCombs School of Business at the University of Texas at Austin. My 6 business address is Department of Finance, The University of Texas at 7 Austin, 1 University Station B6600, Austin, Texas 78712. 8 9 Q. DID YOU PREVIOUSLY FILE DIRECT TESTIMONY ON BEHALF OF 10 ENTERGY TEXAS, INC. (“ETI” OR “THE COMPANY”) IN THIS 11 PROCEEDING? 12 A. Yes, I did. 13 14 II. PURPOSE OF REBUTTAL TESTIMONY 15 Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY? 16 A. My Rebuttal Testimony addresses certain arguments raised by Cities 17 witness Garrett, by Staff witness Givens, and by TIEC witness Pollock in 18 opposition to inclusion in rates of what has been termed “financially” 19 related incentive compensation. 3 Entergy Texas, Inc. Page 2 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 III. RESPONSE TO MR. GARRETT’S POLICY ARGUMENTS 2 OPPOSING INCLUSION OF “FINANCIALLY” RELATED 3 INCENTIVE COMPENSATION IN RATES 4 Q. WHAT PORTIONS OF MR. GARRETT’S TESTIMONY ARE YOU 5 ADDRESSING? 6 A. Mr. Garrett makes several arguments as to why “financially” based 7 incentive compensation should be excluded from rates. Specifically, he 8 argues that: 9 1) Payment is uncertain. 10 2) Incentive plans tied to company earnings performance are held in 11 general disfavor because many factors that significantly impact 12 earnings are outside the control of most company employees and 13 have limited value to customers. 14 3) Earnings-based incentive plans can discourage conservation. 15 4) The utility and its stockholders assume none of the financial risks 16 associated with financially based incentive payments. 17 5) Incentive payments based on financial performance measures 18 should be made out of increased earnings. 19 6) Financially based incentive payments embedded in rates shelter 20 the utility against the risk of earnings erosion through attrition. 21 Mr. Garrett goes on to argue that financial incentives differ from 22 operational incentives because ratepayers have no stake in an incentive 23 plan design based on financial performance measures, while they do have 24 a stake in such a plan to the extent it is based on operational performance 4 Entergy Texas, Inc. Page 3 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 measures. There are logical and theoretical problems with these 2 arguments, as I discuss below. Company witness Kevin G. Gardner also 3 addresses the flaws in Mr. Garrett’s analysis. 4 5 Q. PLEASE ADDRESS MR. GARRETT’S ARGUMENT THAT FUTURE 6 PAYMENT OF FINANCIALLY BASED INCENTIVE COMPENSATION IS 7 UNCERTAIN. 8 A. It is true that payment of incentive compensation in the future is designed 9 to be uncertain. Indeed, this is a key aspect of the effectiveness of 10 incentive compensation, because the risk associated with the level of 11 future compensation provides incentives for positive employee 12 performance. However, this uncertainty does not imply that such incentive 13 compensation is an unreasonable, unnecessary, or non-recurring 14 business expense. If Mr. Garrett’s argument were valid, no incentive 15 compensation, whether it is financially or operationally based, would be a 16 candidate for inclusion in rates, which is a position already considered and 17 rejected by the Commission.1 At some level, many future costs of doing 18 business are uncertain at the time rates are set. I understand that by 19 using a “test year,” the Commission has a sample data point that, despite 1 See Application of Oncor Electric Delivery Company for Authority to Change Rates, Docket No. 35717, Proposal for Decision at 100 (Jun 2, 2009) (stating that, despite the fact that incentive compensation plans are conditional by nature, the Commission has allowed recovery based on operational measures) and Order on Rehearing Findings of Fact 91-93 and Ordering Paragraph 1 (Nov. 30, 2009) (adopting the PFD to the degree consistent with the order on rehearing). 5 Entergy Texas, Inc. Page 4 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 this inherent level of uncertainty, becomes the starting point for setting 2 rates. ETI’s incentive compensation plan design provides the potential for 3 payment of incentive compensation at varying levels dependent on the 4 degree of financial success. This potential variation is consistent with the 5 use of the test-year level of incentive compensation payments as the basis 6 for setting rates. 7 8 Q. WHAT IS YOUR RESPONSE TO MR. GARRETT’S POSITION THAT 9 INCENTIVE PLANS BASED ON COMPANY EARNINGS ARE HELD IN 10 GENERAL DISFAVOR BECAUSE MANY FACTORS THAT 11 SIGNIFICANTLY IMPACT EARNINGS ARE OUTSIDE THE CONTROL 12 OF MOST COMPANY EMPLOYEES AND HAVE LIMITED VALUE TO 13 CUSTOMERS? 14 A. Here, Mr. Garrett uses examples of “good luck” to argue that because 15 random chance can influence whether employees make targets or not, 16 this possibility somehow leads to the conclusion that such compensation 17 plans are held in disfavor. Mr. Garrett, however, conveniently ignores the 18 fact that the luck might be bad – e.g., an unseasonably mild summer might 19 weaken the firm’s financial performance and make it less likely that the 20 firm hits some financial targets. Moreover, the impact of such events can 21 also affect the level of performance on operational measures such as 22 reliability, such that Mr. Garrett’s argument raises no meaningful 6 Entergy Texas, Inc. Page 5 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 distinction from the types of incentive payments that the Commission 2 currently allows in rates. 3 The effect of random chance – both positive and negative 4 surprises – is why nearly every overall compensation package provides 5 some component of safe pay, such as salary, instead of consisting of only 6 incentive-based pay. An incentive-only pay package would be too risky 7 from the employee’s perspective and too expensive from the firm’s 8 perspective due to this greater risk. A balanced approach, however, that 9 includes some incentive compensation, adds the possibility of a reward to 10 the negative of risk. Moreover, that possibility of reward motivates 11 employees to take actions that are in the shareholders’ and ratepayers’ 12 best interests. 13 The uncertainty of payment of a portion of their compensation 14 provides incentives for employees to take actions that are in the best 15 interest of shareholders and ratepayers alike. The nature of the workplace 16 is such that it is impossible to perfectly observe and verify the employees’ 17 actions. Instead, one must rely on signals or indications. These signals or 18 indications will include some element of luck or chance. Ultimately, by 19 properly balancing such incentive compensation with fixed salaries, all 20 parties can be better off – employees, shareholders, and customers. 7 Entergy Texas, Inc. Page 6 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 Q. WHAT IS YOUR RESPONSE TO MR. GARRETT’S CONTENTION THAT 2 EARNINGS-BASED INCENTIVE PLANS CAN DISCOURAGE 3 CONSERVATION? 4 A. Mr. Garrett hypothesizes that an earnings-based performance target will 5 improperly motivate employees to disregard beneficial programs such as 6 demand side management, if they perceive that such programs may 7 depress earnings. Mr. Garrett offers no evidence that any such incentive 8 is created by ETI’s incentive plan. Moreover, to the extent that an 9 incentive plan encourages the attraction of incremental customers – such 10 as in connection with an economic development program – it may have 11 the positive result of spreading the Company’s fixed costs among a larger 12 customer base, to the benefit of all customers. More fundamentally, an 13 appropriate balance of performance incentives in the incentive plan design 14 will avoid the result hypothesized. For example, when an incentive plan 15 design balances both earnings targets and cost control performance 16 through budget and process efficiency targets, the design should lead 17 managers to reduce costs, which in the long run will directly benefit 18 customers. At the same time, including performance targets related to 19 reliable service and customer satisfaction helps ensure that cost-cutting 20 does not erode customer service. 8 Entergy Texas, Inc. Page 7 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 Q. IS MR. GARRETT CORRECT THAT THE UTILITY AND ITS 2 STOCKHOLDERS ASSUME NONE OF THE FINANCIAL RISKS 3 ASSOCIATED WITH INCENTIVE PAYMENTS? 4 A. Based on my understanding of the ratemaking process, this statement is 5 false. If the exact level of incentive compensation for every year was 6 included in rates in that year, then it might be true. However, by using a 7 test year and setting the appropriate incentive compensation level based 8 on that year’s data, an expected level of incentive compensation is 9 included in future rates. The utility and shareholders still face financial risk 10 or variation due to fluctuations around that expected level. If incentive 11 compensation is above the amount put in rates, shareholders of the firm 12 will pay that extra amount. 13 In addition, Mr. Garrett’s claim here misses the whole point of 14 incentive compensation. The reason incentive compensation is effective 15 is that it puts a portion of the employees’ pay at risk. The goal is not to put 16 more risk on the shareholders – they are already bearing the risk of the 17 employees’ actions that affect the firms’ profitability. By exposing 18 employees’ pay to risk or variation, employees have an increased 19 incentive to take actions that are in both shareholders’ and ratepayers’ 20 best interests. 9 Entergy Texas, Inc. Page 8 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 Q. IS THERE ANY MERIT TO MR. GARRETT’S CLAIM THAT INCENTIVE 2 PAYMENTS BASED ON FINANCIAL PERFORMANCE MEASURES 3 SHOULD BE MADE OUT OF INCREASED EARNINGS? 4 A. I do not understand Mr. Garrett’s claim or objection here. The test year 5 provides a measure of “expected” or “normal” compensation, including 6 both salaries and reasonable or customary incentive compensation. It is 7 this expected level that is recovered through rates, and thus, shareholders 8 do indeed bear the cost of any additional – or, better than expected – 9 compensation. Thus, what Mr. Garrett claims should happen is exactly 10 what does happen; shareholders pay for compensation that is greater than 11 expectations out of increased earnings. 12 13 Q. IS MR. GARRETT’S VIEW CORRECT THAT INCENTIVE PAYMENTS 14 EMBEDDED IN RATES SHELTER THE UTILITY AGAINST THE RISK OF 15 EARNINGS EROSION THROUGH ATTRITION? 16 A. No. Including a representative level of incentive compensation in rates 17 does not act as a typical financial hedge, unlike the characterization put 18 forth by Mr. Garrett. Hedges act as insurance and pay off more if the 19 firm’s performance weakens. Recovering incentive compensation through 20 rates would provide a level cash flow to the utility, holding revenues 21 constant. If the firm’s performance weakens due to shocks to its cost 22 structure, then this level cash flow would indeed improve its financial 23 stability, but no more so than other cost components of the rates in place. 10 Entergy Texas, Inc. Page 9 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 However, if the performance weakens due to a drop in revenues (for 2 example, due to a drop in electricity consumption), then the cash flow 3 traced to the inclusion of incentive compensation in rates would drop as 4 well (because it is part of the costs that go into establishing the per-unit 5 price). Even if the additional cash flow improves the financial health of the 6 utility, however, a financially healthy utility is in the customers’ best 7 interest. As I pointed out in my Direct Testimony, a utility that is financially 8 unhealthy would likely incur greater costs in the future that would be borne 9 by customers. 10 This last point brings up another problem with Mr. Garrett’s 11 testimony. He states: 12 When incentive compensation payments are based on 13 financial performance measures, the compensation 14 agreement between shareholders and employees could be 15 loosely stated in this manner: “if you increase shareholder 16 earnings, we will pay you a bonus.” The intended 17 beneficiaries to this agreement are the shareholders and the 18 employees. Ratepayers have no stake in this agreement; 19 therefore, they should bear none of the costs that result from 20 such an agreement. If, instead, the agreement were stated 21 in this manner: “if you will help increase reliability and quality 22 of service to the customers, and reduce fuel and purchased 23 power costs, we will pay you a bonus,” then, ratepayers 24 would have a stake in the agreement, and could share in a 25 portion of the costs. (See page 39.) 26 Mr. Garrett’s statement that ratepayers have no stake in the first 27 agreement he references is false in my opinion. Ratepayers are likely to 28 benefit from a financially healthy utility for the many reasons discussed in 29 my Direct Testimony. In addition, a well-balanced incentive plan that 11 Entergy Texas, Inc. Page 10 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 rewards employees based on operational measures in addition to financial 2 measures will help ensure that improvements in shareholders’ welfare do 3 not come at the expense of ratepayers’ welfare. 4 5 Q. IS MR. GARRETT’S STATEMENT THAT RATEPAYERS HAVE NO 6 STAKE IN INCENTIVE COMPENSATION AGREEMENTS BASED ON 7 FINANCIAL PERFORMANCE MEASURES LOGICAL AND CONSISTENT 8 WITH HIS OTHER STATEMENTS? 9 A. No. In addition to the benefits that ratepayers experience from a 10 financially healthy utility (as discussed in my Direct Testimony), perhaps 11 the easiest way to see the error in Mr. Garrett’s argument that ratepayers 12 have no stake in such incentive compensation plans is to consider an 13 incentive plan that motivates employees to achieve increased efficiencies 14 or control costs. Because of the regulatory process, the benefits of any 15 cost controls would be passed along to ratepayers through lower rates in 16 the future. Thus, it seems obvious that it is in the ratepayers’ interests that 17 the utility implements a fair and reasonable incentive compensation plan 18 that motivates employees to control costs. 19 Mr. Garrett admits this point on page 31 of his testimony, where he 20 states: “To the contrary, incentive plans that motivate employees to 21 achieve increased efficiencies (i.e., cost control) should be encouraged.” 22 He goes on to argue that because the utility retains such cost savings 23 between rate cases, the utility should pay for the incentive compensation 12 Entergy Texas, Inc. Page 11 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 rather than the ratepayers. Based on this discussion, it is clear that 2 Mr. Garrett understands that ratepayers ultimately benefit from incentive 3 compensation plans that lead to greater cost control, via the regulatory 4 process. Thus, Mr. Garrett contradicts his later statement on page 39 that 5 ratepayers have no stake in these types of agreements. 6 7 Q. IN ADDITION TO THESE INTERNAL INCONSISTENCIES, DOES MR. 8 GARRETT’S POSITION ALSO CONTRADICT THOSE OF MR. 9 POLLOCK AND MS. GIVENS? 10 A. Yes. Mr. Pollock and Ms. Givens do not object to the inclusion of 11 compensation based on cost controls. In fact, Mr. Pollock acknowledges 12 in his deposition that compensation based on cost controls will tend to 13 benefit ratepayers.2 In contrast, Mr. Garrett includes compensation based 14 on cost controls as financially-based, and then argues that it should be 15 excluded, in spite of his admission that it benefits ratepayers and should 16 be encouraged. 2 See pages 39-40 of Mr. Pollock’s deposition, dated April 9, 2012. 13 Entergy Texas, Inc. Page 12 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 Q. CAN YOU GIVE A SIMPLE EXAMPLE TO ILLUSTRATE THE BENEFIT 2 TO RATEPAYERS OF COST CONTROLS AS PART OF THE 3 REGULATORY PROCESS? 4 A. Yes. Consider a simple example where, due to an incentive 5 compensation plan that rewards cost controls, an employee comes up 6 with an idea that reduces the cost of delivering service by $1 per year, in 7 perpetuity. In order to convert this stream of cost savings into a value 8 today, one needs to use an interest (or discount) rate that captures 9 ratepayers’ and shareholders’ preferences for cash today relative to cash 10 in the future. To use round but plausible numbers, consider the case 11 where ratepayers and shareholders are willing to accept a 10 percent 12 return on their investments. In this case, the $1 annual cost saving would 13 generate $10 of value or wealth (calculated as $10 = $1 / 0.10).3 14 Next, assume that the time between the cost savings and the next 15 rate case is three years. In this example, shareholders receive the benefit 16 of the first three years of cost savings, while ratepayers receive the 17 savings for year four and beyond. Using the 10 percent discount rate, the 18 value of the cost savings that is captured by the shareholders is about 19 $2.49, while the remaining $7.51 accrues to the ratepayers.4 Thus, about 20 25 percent of the value of cost savings is passed to the shareholders, 3 Intuitively, this is the value because one could invest $10 at a 10 percent rate of return and generate the equivalent $1 per year, forever. 4 This is calculated as 1/1.1 + 1/(1.1^2) + 1/(1.1^3) = 2.49, and 10 – 2.49 = 7.51. 14 Entergy Texas, Inc. Page 13 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 while 75 percent goes to the ratepayers. Clearly, the ratepayers have a 2 stake in the agreement that provided the employee with the incentive to 3 control costs. In fact, in this scenario, the ratepayers’ stake is even more 4 significant than that of the shareholders. 5 6 IV. RESPONSE TO MR. POLLOCK’S AND MS. GIVENS’ 7 POLICY ARGUMENTS OPPOSING INCLUSION OF 8 “FINANCIALLY” RELATED INCENTIVE 9 COMPENSATION IN RATES 10 Q. WHAT PORTIONS OF MR. POLLOCK’S AND MS. GIVENS’ TESTIMONY 11 ARE YOU ADDRESSING? 12 A. Mr. Pollock and Ms. Givens both discuss incentive compensation, and 13 assert that compensation expense related to achieving financial objectives 14 should be disallowed. 15 16 Q. DO YOU AGREE WITH MR. POLLOCK’S STATEMENT THAT 17 INCENTIVE COMPENSATION BASED ON ACHIEVING CERTAIN 18 FINANCIAL GOALS OF ENTERGY SHOULD BE DISALLOWED ON THE 19 BASIS THAT IT BENEFITS ONLY SHAREHOLDERS NOT 20 CUSTOMERS? 21 A. No. Mr. Pollock makes this statement on pages 41-42 of his testimony. 22 As discussed earlier in this Rebuttal Testimony and in my Direct 23 Testimony, there are several reasons why ratepayers benefit from a 24 financially healthy utility. Incentive compensation based on financial 15 Entergy Texas, Inc. Page 14 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 measures is an important tool used to promote financial health, which in 2 turn tends to benefit ratepayers. 3 4 Q. DOES MR. POLLOCK OFFER ANY ADDITIONAL SUPPORT FOR HIS 5 CLAIM THAT INCENTIVE COMPENSATION EXPENSE LINKED TO 6 FINANCIAL PERFORMANCE SHOULD BE EXCLUDED? 7 A. Beyond his assertion that ratepayers do not benefit from a financially 8 healthy utility or from cost controls, Mr. Pollock’s recommendation appears 9 to be based solely on past precedent. On page 44, in response to the 10 question, “What is the basis for your recommendation?” he states, “My 11 recommendation is consistent with past precedent,” and goes on to 12 discuss previous Commission findings. He does not present additional 13 analysis of his own in support of his recommendation. 14 15 Q. DOES MS. GIVENS OFFER ANY ADDITIONAL SUPPORT FOR HER 16 CLAIM THAT INCENTIVE COMPENSATION EXPENSE LINKED TO 17 FINANCIAL PERFORMANCE SHOULD BE EXCLUDED? 18 A. Like Mr. Pollock, Ms. Givens’ recommendation appears to be based solely 19 on past precedent. She discusses this history on pages 16-18 of her 20 testimony, but she does not present additional analysis of her own in 21 support of her recommendation. 16 Entergy Texas, Inc. Page 15 of 15 Rebuttal Testimony of Jay C. Hartzell, Ph.D. Docket No. 39896 1 V. CONCLUSION 2 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY? 3 A. Yes. 17 12 Cathleen Parsley Chief Administrative Law Judge July 6, 2012 TO: Stephen Journeay, Director COURIER PICK-UP Commission Advising and Docket Management William B. Travis State Office Building 1701 N. Congress, 7th Floor Austin, Texas 78701 RE: SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment Enclosed is the Proposal for Decision (PFD) in the above-referenced case. By copy of this letter, the parties to this proceeding are being served with the PFD. Please place this case on an open meeting agenda for the Commissioners' consideration. The jurisdictional deadline for this case is July 30, 2012. Please notify me and the parties of the open meeting date, as well as the deadlines for filing exceptions to the PFD, replies to the exceptions, and requests for oral argument. :Ji;;;:-J. Steven D. Arnold Administrative Law Judge Enclosure xc: All Parties of Record 300 W. 15th Street, Suite 502, Austin, Texas 78701/ P.O. Box 13025, Austin, Texas 78711-3025 512.475.4993 (Main) 512.475.3445 (Docketing) 512.322.2061 (Fax) www.soah.state.tx.us SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE INC. FOR AUTHORITY TO CHANGE § RATES, RECONCILE FUEL COSTS, § OF AND OBTAIN DEFERRED § ACCOUNTING TREAT:MENT § ADMINISTRATIVE HEARINGS PROPOSAL FOR DECISION I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4] Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail service area located in southeastern Texas. ETI serves retail and wholesale electric customers in Texas. As ofJune 30, 2011, ETI served approximateI y 412,000 Texas retail customers. The Federal Energy Regulatory Commission (FERC) regulates ETI's wholesale electric operations. On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed increase in annual base rate revenues of approximately $111.8 million over adjusted revenues for the period beginning July 1, 2010, and ending June 30, 2011 (Test Year); (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities accompanying ETI' s application and including new riders for recovery of costs related to purchased power capacity and renewable energy credit requirements; (3) a request for final reconciliation of ETI's fuel and purchased power costs for the reconciliation period from July 1, 2009, to June 30, 2011 (Reconciliation Period); and (4) certain waivers to the instructions in Rate Filing Package Schedule V accompanying ETI' s application. The rate year for ETI' s proposed changes is June 1, 2012, through May 31, 2013 (Rate Year). 1 On April 13, 2012, adjusted its request for a proposed increase in annual base rate revenues to approximately $104.8 million over adjusted Test Year revenues. 1 During the hearing the parties used the term "Rate Year" to refer to the period June 2012 through May 2013. This was intended to represent the first 12 months of the rates adopted in this case. However, the rates in this case will not go into effect (as temporary rates) until at least June 30, 2012. Nevertheless, for purposes of this PFD, Rate Year will refer to the period June 2012 through May 2013. SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 166 PUC DOCKET NO. 39896 the corrections to Staffs adjustments that were suggested by ETI, and the AU s can find no basis for challenging those corrections. Thus, the Al.Js 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., TIEC 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. SOAH DOCKET NO. XXX-XX-XXXX 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 turn 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 NO. XXX-XX-XXXX 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 opm10n, 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 financially 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. SOAH DOCKET NO. XXX-XX-XXXX 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 NO. XXX-XX-XXXX 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 NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 171 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 ALls conclude that ETI should not be entitled to recover its financially based incentive compensation costs. Based upon prior Commission precedents, the AU s 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 ALls 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 NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 172 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 ofETI'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 AU s 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. at 481-82. SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 173 PUC DOCKET NO. 39896 590 argues that $5.3 million ofETI's incentive compensation is financiallybased. TIEC contends the 592 correct number is $6.2 million. 591 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 ,3 23, 798 (representing ETI' s financially based incentives paid in the Test Year, plus FICA taxes associated with those payments) fromETI's requested O&M expenses. 595 590 Staff Initial Brief at 56. (As discussed more below, Staffs 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. 1 (Givens Direct) at 15-22; Staff Initial Brief at 56-63. SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 174 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) from ETI'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. 1 (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. SOAH DOCKET NO. XXX-XX-XXXX 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 AUs 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, the AU s recommend removing $6, 196,03 7 (representing ETI' s financially based incentives paid in the Test Year) from ETI's requested O&M expenses. Additionally, the AlJs agree with Staff and 60 ° 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 NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 176 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. PUC DOCKET NO. 39896 SOAH DOCKET NO. XXX-XX-XXXX APPLICATION OF ENTERGY TEXAS, § INC. FOR AUTHORITY TO CHANGE § RATES, RECONCILE FUEL COSTS, § AND OBTAIN DEFERRED § ACCOUNTING TREATMENT § ORDER 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 (AUs) 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 AUs also recommended approving total fuel costs of approximately $1.3 billion. The AUs 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 AUs 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. 1 Supplemental Preliminary Order at 2, 3 (Jan. 19, 2012). 2 Letter from SOAHjudges to PUC (Aug. 8, 2012). 000000001 PUC Docket No. 39896 Order Page 2 of 43 SOAH Docket No. XXX-XX-XXXX 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 (SPAS) 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 SPAS 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 (AFUDC). 6 The ALls concluded that this approach was sound and should be followed in this case. 7 Thus, the AU s 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 ALls 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 Commission 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 ADFIT. 3 Proposal for Decision at 23 (July 6, 2012) (PFD). 4 PFD at 23-24. 5 Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 33309, Order on Rehearing (March 4, 2008). 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 PFDat 26. 8 Id. at 24-26. 000000002 PUC Docket No. 39896 Order Page 3 of43 SOAH Docket No. XXX-XX-XXXX 8. 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 $5,916,461. 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 AUs 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 IRS attributable to Entergy's FIN 48 liability should not be included in Entergy's ADFIT balance. Accordingly, the AUs 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 ADFIT balance and thus be used to offset Entergy's rate base. 10 The AUs 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. 9 PFD at 26-27 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 6), 29 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 8). 10 PFD at 29. 11 Id. 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 ). 000000003 PUC Docket No. 39896 Order Page 4of43 SOAH Docket No. XXX-XX-XXXX 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. 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 Al.Js 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 l, 2009 through June 30, 2010 that were financially based was excluded from Entergy's rate base. The AU s 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 Al.Js adopted the method advocated by Texas Industrial Energy Consumers (TIEC) for 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 TIEC' s methodology to also calculate the amount of capitalized incentive compensation that is financially based. Entergy also noted that the amount of the disallowance reflected in the 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). 000000004 PUC Docket No. 39896 Order Page 5 of43 SOAH Docket No. XXX-XX-XXXX schedules, $1,333,352, was calculated using a disallowance factor that included incentive compensation tied to cost-control measures, which the AUs 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 methodology is that only $335,752.96 should be disallowed from capital costs. 17 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 1, 2009 through June 30, 2010. However, the Commission finds that a consistent methodology should be used to calculate the amount to be 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 determination. 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 151 is modified to reflect this adjustment to property taxes. D. Rate of Return and Cost of Capital The AUs 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 AUs found that the effect 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 AU s 16 Entergy's Exceptions to the Proposal for Decision at 25-26. 17 Id. at 25-26. 18 Commission Number-Run Memorandum at 2 (Aug. 28, 2012). 19 PFD at 94. 20 Id. 000000005 PUC Docket No. 39896 Order Page6 of43 SOAH Docket No. XXX-XX-XXXX 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 AU s that a utility's return on equity should be determined using an adder to reflect unsettled economic conditions facing utilities. The Commission agrees with the AUs, 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 AUs. A return on equity of 9.80 percent is within the range of an acceptable return on equity found by the AUs. Accordingly, the Commission adds new finding of fact 65A to reflect the Commission's decision on this point. E. Purchased-Power Capacity Expense The AU s rejected Entergy' s request to recover $31 million more in purchased-power capacity costs than its actual test-year expenses because Entergy had failed to prove that the adjustment was known and measurable, 23 and because the request violated the matching principle. 24 Consequently, the AUs 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 decision. 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 21 Id. at 94. 22 PURA§§ 36.051, .052. 23 PFD at 108-09. 24 Id. at 109. is Id. 26 Entergy' s Exceptions to the Proposal for Decision at 51. 000000006 PUC Docket No. 39896 Order Page 7 of 43 SOAH Docket No. XXX-XX-XXXX 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 Al.Js found that $6,196,037, representing Entergy's financially-based incentives paid in the test-year, should be removed from Entergy's O&M expenses. 27 The Al.Js 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. The Commission agrees with the Al.Js, 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. Affiliate 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 Al.Js 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 27 PFD at l 75. 28 Id. at l 75-76. 29 See Commission Number Run-Memorandum at 3 (Aug. 28, 2012). 30 Direct Testimony of Carol Szerszen, OPUC Ex. I at 44-45. 000000007 PUC Docket No. 39896 Order Page 8of43 SOAH Docket No. XXX-XX-XXXX 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 E10PCR56224 - 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 (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 164A is added to reflect the proper allocation of these affiliate transactions. 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 31, 2010, which falls in the middle of the two year fuel reconciliation period-July 2009 through June 2011-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. SUBST. R. 25.236. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to include any issue related to the reasonableness of a utility's fuel expenses and whether the utility has over- or under-recovered its reasonable fuel expenses. 33 Cities calculated a $3,981,271 reduction to the Texas retail fuel expenses incurred over the reconciliation period using the current line-losses. The AUs rejected Cities' proposed adjustment finding that the P.U.C. SUBST. R. 25.237(c)(2)(B) requires the use of Commission- 31 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. l at Schedule CAS-7. 33 Cities' Exceptions to the Proposal for Decision at 20-21 (July 23, 2012). 000000008 PUC Docket No. 39896 Order Page 9of43 SOAH Docket No. XXX-XX-XXXX 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 utilized in Entergy's fuel reconciliation. The Commission finds that Entergy's 2010 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 19A and 19B are added to reflect the Commission's finding that the 2010 line-loss factors be used to reconcile Entergy's fuel costs. 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. 34 PFD at 327-328. 35 Open Meeting Tr. at 138 (Aug. 17, 2012). 36 Id. 000000009 PUC Docket No. 39896 Order Page 10 of 43 SOAH Docket No. XXX-XX-XXXX K. Other Issues New findings of fact 17 A, 17B, 17C, 17D, 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 AUs, findings of fact 116, 123, 192, 194, and 202 are modified; and new finding of fact 182A 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. 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 000000010 PUC Docket No. 39896 Order Page 11 of43 SOAH Docket No. XXX-XX-XXXX 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, 2011, the Commission referred this case to the State Office of Administrative Hearings (SOAH). 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 (ALls) 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 AUs issued SOAH Order No. 4 granting the motions for admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and participate as counsel for Kroger and the motion for admission pro hac vice filed by Rick D. Chamberlain to appear and participate as counsel for Wal-Mart. 000000011 PUC Docket No. 39896 Order Page 12 of43 SOAH Docket No. XXX-XX-XXXX 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 ALls 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. 17. Initial post-hearing briefs were filed on May 18 and reply briefs were filed on May 30, 2012. 17A. On August 7, 2012, the SOAH ALls filed a letter with the Commission recommending changes to the PFD. 17B At the July 27, 2012 open meeting, ETI agreed to extend the effective date of rates to August 31, 2012 to provide the Commission sufficient time to 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, 2012 open meeting, ETI agreed to extend the effective date of rates to September 14, 2012. 17E. At the August 17, 2012 open meeting, parties announced on the record a settlement of the amount of costs for the transition to MISO. 000000012 PUC Docket No. 39896 Order Page 13 of43 SOAH Docket No. XXX-XX-XXXX 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 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. 000000013 PUC Docket No. 39896 Order Page 14 of43 SOAH Docket No. XXX-XX-XXXX 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 $8,858,933. 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 (FASB) Financial Interpretation No. 48 (FIN 48), "Accounting for Uncertainty in Income Taxes," requires ETI to identify each of its uncertain tax positions by evaluating the 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 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. 000000014 PUC Docket No. 39896 Order Page 15 of43 SOAH Docket No. XXX-XX-XXXX 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 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 FIN 48 liability. 40A. It is appropriate for ETI to create a deferred-tax-account tracker in the form of a rider to recover on a prospective basis an after-tax return of 8.27% on the amounts paid to the IRS that result from an unfavorable FIN 48 audit. The rider will track unfavorable FIN 48 rulings and the return will be applied prospectively to FIN 48 amounts disallowed by an IRS audit after such amounts are actually paid to the federal government. If ETI prevails in an appeal of a FIN 48 decision, then any amounts collected under the rider related to that decision should be credited back to ratepayers. 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 ETI considered the actual operations of ETI, adjusted for known and measurable changes, and is consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii). 000000015 PUC Docket No. 39896 Order Page 16 of43 SOAH Docket No. XXX-XX-XXXX 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. 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. 000000016 PUC Docket No. 39896 Order Page 17 of 43 SOAH Docket No. XXX-XX-XXXX Staffs proposed adjustments should be incorporated into the calculation of ETI' s rate base. 56. The following short-term asset amounts should be included in rate base: prepayments at $8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485. 57. The amount of $1,127,778, representing costs incurred by ETI when it acquired the Spindletop facility, represent actual costs incurred to process and close the acquisition, not mere mark-up costs. 58. ETI's $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. ETI's capitalized incentive compensation that is financially based is $335,752.96 and should be removed for rate base. 62. The test-year for ETI's prior ratemaking proceeding ended on June 30, 2009, and the reasonableness of ETI's capital costs (including capitalized incentive compensation) for that prior period was dealt with by the Commission in that proceeding and is not at issue in this proceeding. 63. In this proceeding, ETI's capitalized incentive compensation that is financially-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). 000000017 PUC Docket No. 39896 Order Page 18 of43 SOAH Docket No. XXX-XX-XXXX Rate o(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. 65A. It is not appropriate to add 15 points to the ROE due to unsettled economic conditions facing utilities. 66. A 9.80 percent ROE is consistent with ETI's business and regulatory risk. 67. ETI's proposed 6.74 percent embedded cost of debt is reasonable. 68. The appropriate capital structure for ETI is 50.08 percent long-term debt and 49.92 percent common equity. 69. A capital structure composed of 50.08 percent debt and 49.92 percent equity is reasonable in light of ETI' s business and regulatory risks. 70. A capital structure composed of 50.08 percent debt and 49.92 percent equity will help ETI attract capital from investors. 71. ETI's overall rate of return should be set as follows: CAPITAL WEIGHTED 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 $245,965,886. 73. ETI requested an upward adjustment of $30,809,355 as a post-test-year adjustment to its purchased capacity costs. This request was based on ETI' s projections of its purchased capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the rate-year). 000000018 PUC Docket No. 39896 Order Page 19 of43 SOAH Docket No. XXX-XX-XXXX 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. 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. 000000019 PUC Docket No. 39896 Order Page 20of43 SOAH Docket No. XXX-XX-XXXX 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 speculative because it depends on a number of variables, including future transmission investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating expenses, and loads of each of the Entergy operating companies. 91. ETI seeks increased transmission equalization expenses for transmission projects that are not currently used and useful in providing electric service. ETI's post-test-year adjustment is based on the assumption that certain planned transmission projects will go into service after the test-year. At the close of the hearing, none of the planned transmission projects had been fully completed and some were still in the planning phase. 92. It is not reasonable for ETI to charge its retail ratepayers for transmission equalization expenses related to projects that are not yet in-service. 93. ETI's request for a post-test-year adjustment of $8,942,785 for rate-year transmission equalization expenses should be denied because those expenses are not known and measurable. ETI's post-test-year adjustment does not with reasonable certainty reflect what ETI' s transmission equalization expense will be when rates are in effect. 94. ETI's transmission equalization expense in this case should be based on the test-year level of $1,753,797. 000000020 PUC Docket No. 39896 Order Page 21of43 SOAH Docket No. XXX-XX-XXXX 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. 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 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. 000000021 PUC Docket No. 39896 Order Page 22 of43 SOAR Docket No. XXX-XX-XXXX 106. The net salvage rate of negative 30 percent for ETI's transmission overhead conductors and devices (FERC Account 356) is the most reasonable of those proposed and should be adopted. 107. A service life of 65 years and a dispersion curve of R3 for ETI' s distribution structures and improvements (FERC Account 361) are 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 of L4 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. 000000022 PUC Docket No. 39896 Order Page 23 of43 SOAH Docket No. XXX-XX-XXXX 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 positive five percent for ETI's distribution line transformers (FERC Account 368) is the most reasonable of those proposed and should be adopted. 117. The net salvage rate of negative 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. 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 391.2). Therefore, a five year amortization for this account is reasonable and should be adopted. 124. ETI proposed adjustments to its test-year payroll costs to reflect: (a) changes to employee headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage increases set to go into effect after the end of the test-year. 125. The proposed payroll adjustments are reasonable but should be updated to reflect the most recent available information on headcount levels as proposed by Commission Staff. 000000023 PUC Docket No. 39896 Order Page 24 of43 SOAH Docket No. XXX-XX-XXXX 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. 131. The $5,376,975 that was paid for long term incentive programs was tied to financial measures and, therefore, should not be included in ETI' s cost of service. 132. Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062 was tied to financial measures and, therefore, should be disallowed. 133. In total, the amount of incentive compensation that should be disallowed is $6,196,037 because it was related to financial measures that are not reasonable and necessary for the provision of electric service. An additional reduction should be made to account for the 000000024 PUC Docket No. 39896 Order Page 25 of43 SOAR Docket No. XXX-XX-XXXX 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. 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 reasopable 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. 000000025 PUC Docket No. 39896 Order Page 26 of43 SOAH Docket No. XXX-XX-XXXX 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 pro Jonna 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 pro Jonna 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. Staffs 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. 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 000000026 PUC Docket No. 39896 Order Page 27 of43 SOAH Docket No. XXX-XX-XXXX 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. 25.23 l(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 facili.ty 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 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 000000027 PUC Docket No. 39896 Order Page 28 of43 SOAH Docket No. XXX-XX-XXXX 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. 164A. 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: (1) $46,490 for Project ElOPCR56224 - 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: (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. 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/Senf 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. 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. 000000028 PUC Docket No. 39896 Order Page 29 of43 SOAR Docket No. XXX-XX-XXXX 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 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 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. 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. 000000029 PUC Docket No. 39896 Order Page30 of43 SOAH Docket No. XXX-XX-XXXX 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. l 82A. 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. 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 in its next rate case. 000000030 PUC Docket No. 39896 Order Page 31of43 SOAH Docket No. XXX-XX-XXXX 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. 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 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. 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) 75% 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§ 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 000000031 PUC Docket No. 39896 Order Page 32 of43 SOAH Docket No. XXX-XX-XXXX 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 (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. 000000032 PUC Docket No. 39896 Order Page 33 of43 SOAH Docket No. XXX-XX-XXXX 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 Enenzv 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 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. 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. 000000033 PUC Docket No. 39896 Order Page 34 of43 SOAH Docket No. XXX-XX-XXXX 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. 000000034 PUC Docket No. 39896 Order Page 35 of43 SOAH Docket No. XXX-XX-XXXX 212. Schedule RS winter block rates should be modified consistent with the goal set out in PU,RA § 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. 000000035 PUC Docket No. 39896 Order Page36 of43 SOAH Docket No. XXX-XX-XXXX 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, 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 000000036 PUC Docket No. 39896 Order Page37 of43 SOAH Docket No. XXX-XX-XXXX 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. 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 to each operating company on a monthly basis. 000000037 PUC Docket No. 39896 Order Page 38 of43 SOAH Docket No. XXX-XX-XXXX 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. 246A. ETI's 2010 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. 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. 000000038 PUC Docket No. 39896 Order Page 39of43 SOAH Docket No. XXX-XX-XXXX 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. 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 $1.6 million in base rates for MISO transition expense. 252. Deleted. 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. 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. 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. 000000039 PUC Docket No. 39896 Order Page40 of43 SOAH Docket No. XXX-XX-XXXX 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. 22.51(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. 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. 25.231(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. 25.231(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§§ 36.051and36.052. 000000040 PUC Docket No. 39896 Order Page 41of43 SOAH Docket No. XXX-XX-XXXX 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. 25.23 l(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). 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). 19A. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding. 19B. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to include any issue related to the reasonableness of a utility's fuel expenses and whether the utility has over- or under-recovered its reasonable fuel expenses. It is proper to use the new line-loss study to calculate Entergy's fuel reconciliation and over-recovery. 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. 000000041 PUC Docket No. 39896 Order Page 42 of 43 SOAH Docket No. XXX-XX-XXXX 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: 1. The proposal for decision prepared by the SOAH AL.Js 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 Tariff 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 Staff's 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 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 000000042 PUC Docket No. 39896 Order Page 43 of 43 SOAH Docket No. XXX-XX-XXXX 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. 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 AT AUSTIN, TEXAS the ~day of September 2012. PUBLIC UTILITY COMMISSION OF TEXAS 2~~IRMAN 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); $372,919 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. q:\cadm\orders\final\39000\39896fo2.docx 37 Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965, Second Order on Rehearing (Oct. 16, 1997). 000000043 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 40295 ETI Exhibit No. 4 SOAH DOCKET NO. XXX-XX-XXXX DOCKET NO. 39896 APPLICATION OF ENTERGY § BEFORE THE STATE OFFICE TEXAS, INC. FOR AUTHORITY § TO CHANGE RATES, RECONCILE § OF FUEL COSTS, AND OBTAIN § DEFERRED ACCOUNTING § ADMINISTRATIVE HEARINGS TREATMENT § SUPPLEMENTAL DIRECT TESTIMONY OF MICHAEL P. CONSIDINE ON BEHALF OF ENTERGY TEXAS, INC. MARCH 2012 1 ~q ~ 36 ENTERGY TEXAS, INC. SUPPLEMENTAL DIRECT TESTIMONY OF MICHAEL P. CONSIDINE DOCKET NO. 39896 TABLE OF CONTENTS I. WITNESS INTRODUCTION 1 II. PURPOSE OF SUPPLEMENTAL TESTIMONY 1 Ill. UPDATE REGARDING INTERNAL RATE CASE EXPENSES 2 IV. RECOVERY OF RATE CASE EXPENSES 5 EXHIBIT Exhibit MPC-SD-1 Requested Rate Case Expenses Exhibit MPC-SD-2 ESI Payroll, Benefits, and Taxes Charged to ETI by Affiliate Class 2 37 Entergy Texas, Inc. Page 1of5 Supplemental Direct Testimony of Michael P. Considine Docket No. 39896 1 I. WITNESS INTRODUCTION 2 a. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 3 A. My name is Michael P. Considine. My business address is 425 West 4 Capitol Avenue, Little Rock, Arkansas 72201. I am employed by Entergy 5 Services, Inc. ("ESr), the service company affiliate of Entergy Texas, Inc. 6 ("ETI" or the "Company") as a Senior Staff Accountant in the Rate Design 7 and Administration Department. 8 9 a. DID YOU PREVIOUSLY FILE TESTIMONY IN THIS PROCEEDING? 10 A. Yes. I filed direct testimony as part of the Company's rate filing package. 11 12 II. PURPOSE OF SUPPLEMENTAL DIRECT TESTIMONY 13 a. WHAT IS THE PURPOSE OF YOUR SUPPLEMENTAL DIRECT 14 TESTIMONY? 15 A. My supplemental direct testimony supports and updates the Company's 16 request to recover rate case expenses associated with this proceeding. 17 Specifically, I provide the levels of rate case expenses incurred (that is, 18 recorded on the Company's books) as of January 31, 2012, related to: (1) 19 outside accounting services, outside legal counsel, and consultants 20 ("external rate case expenses"); and (2) ETI direct expenses and ESI 21 payroll, benefits, and taxes ("internal rate case expenses"). In addition, I 22 address the reasonableness and necessity of the internal rate case 23 expenses. Company witness Mr. Stephen Morris has filed direct, and now 3 38 Entergy Texas, Inc. Page2of5 Supplemental Direct Testimony of Michael P. Considine Docket No. 39896 1 supplemental direct, testimony addressing the reasonableness and 2 necessity of external rate case expenses. 3 4 Ill. UPDATE REGARDING INTERNAL RATE CASE EXPENSES 5 Q. SINCE FILING ITS RATE FILING PACKAGE, HAS THE COMPANY 6 PROVIDED ITS INCURRED RATE CASE EXPENSES? 7 A. Yes. On February 21, 2012, in response to Staff Request for Information 8 ("RFI") 9-1, the Company filed schedules of: (1) external rate case 9 expenses as of December 31, 2011; and 2) internal rate case expenses 10 as of December 31, 2011. 11 12 Q. DO YOU PROVIDE AN UPDATE REGARDING THE LEVELS OF 13 INCURRED RATE CASE EXPENSES IN YOUR SUPPLEMENTAL 14 DIRECT TESTIMONY? 15 A. Yes. The Company's Addendum to its response to Staff RFI 9-1 is 16 attached as Exhibit MPC-SD-1, which presents external rate case 17 expenses by vendor and internal rate case expenses by ETI direct 18 expense category and ESI department. As shown in Exhibit MPC-SD-1, 19 as of January 31, 2012, the Company had incurred $1,963, 113 in external 20 rate case expenses and $2,173,124 in internal rate case expenses. The 21 Company requests recovery of these external and internal rate case 22 expenses. 4 39 Entergy Texas, Inc. Page 3of5 Supplemental Direct Testimony of Michael P. Considine Docket No. 39896 1 Q. HAVE YOU REVIEWED THE INCURRED INTERNAL RATE CASE 2 EXPENSES PRESENTED IN EXHIBIT MPC-SD-1 TO DETERMINE 3 WHETHER SUCH EXPENSES ARE REASONABLE AND NECESSARY? 4 A. Yes. 5 6 Q. HOW DID YOU DETERMINE WHETHER THE INCURRED INTERNAL 7 RATE CASE EXPENSES PRESENTED IN EXHIBIT MPC-SD-1 WERE 8 REASONABLE AND NECESSARY? 9 A. Internal rate case expenses are all captured in Project Code 10 F5PPETX011. The project code is used only for time and expense 11 related to this rate case, and all costs incurred by ESI in this project code 12 are directly billed to ETI. The process through which costs are billed to 13 project codes is described in Company witness Stephanie B. Tuminello's 14 direct testimony. In addition, the Company's affiliate class witnesses, 15 including those who address the ETI direct charges, explain how the 16 budgeting and cost control processes work within their business units. 17 For example, timesheet and expense reports are reviewed by supervisors 18 to ensure accuracy. Also, Company witness Kevin G. Gardner supports 19 the reasonableness and necessity of the compensation and benefits paid 20 to ESI employees. 21 Company witnesses have presented direct testimony regarding the 22 various classes of affiliate costs that ETI receives from ESI, and my 23 Exhibit MPC-SD-2 shows the ESI rate case charges to ETI by affiliate 5 40 Entergy Texas, Inc. Page4 of5 Supplemental Direct Testimony of Michael P. Considine Docket No. 39896 1 class. The processes and practices described in the Company's direct 2 testimony regarding billing, budgeting, cost control, compensation, and 3 benefits remain in effect today. These processes and practices help to 4 ensure that the requested internal rate case expenses are necessary and 5 reasonable, represent the actual costs of the services, do not include 6 prohibited expenses, do not include charges for duplicative services or 7 expenses, and are no higher than the prices charged to other affiliates, or 8 to non-affiliates, for the same or similar classes of item. 9 Further, a review of the Company's requested rate case expenses 10 is undertaken to determine that only appropriate charges are included in 11 the rate case expense request, and inappropriate charges, such as 12 charges for luxury items or excessive meals charges, are excluded. 13 14 Q. WHAT DID YOU CONCLUDE WITH RESPECT TO THE 15 REASONABLENESS AND NECESSITY OF THE COMPANY'S 16 INCURRED INTERNAL RATE CASE EXPENSES? 17 A Based on my review and analysis, as described above, the Company's 18 incurred internal rate case expenses are reasonable and necessary. 6 41 Entergy Texas, Inc. Page5of5 Supplemental Direct Testimony of Michael P. Considine Docket No. 39896 1 IV. RECOVERY OF RATE CASE EXPENSES 2 Q. HOW DOES THE COMPANY PROPOSE TO RECOVER RATE CASE 3 EXPENSES? 4 A. As explained in my direct testimony, the Company proposes that it be 5 permitted to recover all incurred rate case expenses over a three-year 6 period, with a return on the unamortized balance. 7 8 Q. WILL THE COMPANY PROVIDE ADDITIONAL UPDATES REGARDING 9 THE LEVEL OF INCURRED RATE CASE EXPENSES? 10 A. Yes. Staff RFI 9-1 requests that ETI provide monthly updates regarding 11 the level of incurred rate case expenses. ETI will provide the next update 12 to Staff RFI 9-1 on or around March 21, 2012. 13 14 Q. WILL YOU PROVIDE ADDITIONAL SUPPLEMENTAL TESTIMONY 15 REGARDING THE REASONABLENESS AND NECESSITY OF 16 INCURRED INTERNAL RATE CASE EXPENSES? 17 A. It is likely that I will file additional supplemental direct testimony regarding 18 the reasonableness and necessity of internal rate case expenses incurred 19 after those addressed herein. 20 21 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL DIRECT 22 TESTIMONY? 23 A. Yes. 7 42 Exhibit MPC-SD-1 Docket No. 39898 Page 1 of2 ENTERGY TEXAS, INC. RATE CASE EXPENSES RECORDED THROUGH THE MONTH ENDED JANUARY 31, 2012 ETI 6/30/11 COS DOCKET 39896 AMOUNT ACCQUNDNG DELOITTE & TOUCHE LLP Total 915,970 LESS: NON-CONFORMING D&T EXPENSES (2,373) PRICEWATERHOUSE COOPERS LlP Total 122,168 LESS: NON-CONFORMING PWC EXPENSES (7) ACCOUNTING TOTAL 1,035,758 • CON8lJLTAND EXPERT POWERHOUSE LLC OBA EXPERGY 104,689 FINANCOINC 15,051 GERALD WTUCKER CPA 56,575 JAY HARTZELL 8,100 CONSULTANTS TOTAL 184,415 * DUGGINS VIJREN MANN & ROMERO LlP 742,975 LESS: NON-CONFORMING D\Mv'IR EXPENSES (35) LEGAL BILLS RECEIVED BUT NOT PAID LEGAL TOTAL 742,940 * COMPANX DIRECT EX'.PENSE§ Business Meals/Entertainment 1,627 CHle8 BIBS-Lawton Law Firm 22,220 Computer & Office Supplies 189 Court Transatpts Depreciation Expense-General 97,103 Employee Mtgs/Functlons 2,686 Equipment And Other Rentals Legal Notices 98,ns Lodging 3,679 Long Distance Charges Other Employee Expenses 879 Other Office & General 5,401 Personal Car MHeage • Local 595 Ponting, MalUng & Shipping 3,49S Safety Training Loader 1,291 Se!Vlce Company Recipient 206.740 Temporary SelVlces 10,494 Travel Transportation 5,114 UtlUty BIDa 2,518 COMPANY DIRECT EXPENSES TOTAL 462,806 ES! PAYROLL BENEflD & TA)(ES 1,710,318 SEE DETAIL ON PAGE 2 ACDJAL RAD CAU EX'.PENSU IltROUQH 1131(1f 4,136,237 * Please refer to the Company's response and addend urns to Staff RFI 9-1 for detail supporting ti'le Accounting, Consultant, and Legal expenses addressed above. Amounts for Duggins Wren Mann & Romero, LLP Include fees and expenses from the following consultants: Commonwealth Consulting; Alllance Consulting; LeWla & Ellla; and Naman, Howell, Smith & Lee. 8 43 ENTERGY TEXAS, INC. RATE CASE PAYROLL FOR ESI EMPLOYEES THROUGH THE MONTH ENDED JANUARY 31, 2012 Extibll MPC-SD-1 ETI 8130111 COS DOCKET 39898 Docket No. 39896 Page 2 of2 DEPARTIEfr WAGES HOURS ACTIVITIES Dir, CrpAvtn, Secll' &R.E. Op 1,423 17 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Colledlont, Eel Detail 498 14 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES Remillance PIOCllllklg-Esl 120 e ASSIST IN RATE CASE PREPARATION &RFI RESPONSES Csc Cullarler Contact Solutna 14,064 137 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES Cua1crn9r Load lntlm'llllon Adm 8,488 136 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES Bod Feea,Crp Dues ·Eli 36,705 • ASSIST IN RATE CASE PREPARATION &RFI RESPONSES Revenue Requirement &~ 1s1.m 2,489 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES Rate Oellgn & Admlnlltnltlon 107,871 1,737 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Regulaloly Lltfglllon Support 87,808 2,537 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Director· Regutmory Proj9cts 10,258 136 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES Forecatil111 &Alllllyala 981 21 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Fuel & Special Ridenl 9,885 154 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Planning Anllylla 220 2 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Vp Regulalory Seivlca 2.170 13 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ~Optimization 517 9 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Regula1Dry Accounting 280,150 3,937 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Mldg R....at & Forecutrng 780 11 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Whollllle Bllllnese 1,977 19 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Diltrlbutlon Enginlel1ng Delli 22,838 288 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Prof Collif9Fi.d AIMta Opna 2,950 49 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Acc:ounll Payable 9,582 378 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Afliftal8 Al::c:l'g & Allocations 78,804 1,359 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Corporate Plarri1g & Pedorm 3,238 59 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES E>demal Reporting 18,784 380 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES Con1RJller Utllty Opel1lllona 4,520 87 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES CFO: ~ Openltlon1 7,549 82 ASSIST IN RATE CASE PREPARATION &RFI RESPONSES Sllte And Local T - 20,132 241 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Regutab'y TIX SUpport 25,978 178 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 0111ce C!1 Corp Risk C>veralght 103 1 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Aa:ountlng Pollc:y And R-.dl 998 15 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES COfPOl819 Finance 14,323 201 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Buslneee ServicH 13,370 159 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Income TIX Accounting 14,804 249 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Dir, Tax Accounting & Complian 1.942 18 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Anet Managrnent Support 19,682 341 ASSIST JN RATE CASE PREPARATION & RFI RESPONSES Compenaallon & Benefits Design 80,857 723 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES HR~ 2,942 43 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES VP HR Netwolk Operations 1,393 25 ASSIST JN RATE CASE PREPARATION & RFI RESPONSES HR• Project Management 13,614 118 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES HR· Tolal RNalda Prgma 2,978 28 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES HR· Total R-m Ope 357 7 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES HR • Bulineaa Melrk;s 230 3 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Chief Legal Otllcer 58,949 589 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES l.8Qll • l.lllgatlon • TX 4,817 52 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Legal· Generlll Counsel 2,028 25 ASSIST IN RATE CASE PREPARATION & RA RESPONSES Legal • Reg • Corp 1,040 4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Legal • Reg ·TX 10,684 72 ASSIST IN RATE CASE PREPARATION & RA RESPONSES Utllty Convn 0119ctor 509 4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES VP· Advocaq Communleallona 338 9 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Fed11111I Regulaby Alfalnl 758 8 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES WEB COMMUNICATIONS 1,048 15 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Syatem Regulllory Affalre(Dlr) 4,360 88 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Rilk Management 12,122 157 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES lntemal Audit 1,938 29 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES SUPPLY CHAIN BUSINESS SUPPORT 7,311 97 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES DIRECTOR SUPPLY CHAIN SUPPORT 2,158 19 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Regllltly Mrs/Energy Settlmt 74,029 1,157 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES SPO CoqJPance&Contract Adrrin. 549 15 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES SPO Compllanc:e&Buaineaa Supprt 2.435 20 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Generation Planning & Models 2,858 30 ASSIST JN RATE CASE PREPARATION & RFI RESPONSES Supply Pllnnlng andAnalyala 742 18 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES VP Energy Management 487 4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Gen Supvn • Srp&S 7,014 es ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Reguia1Dly Slrallgy 19,915 211 ASSIST IN RATE CASE PREPARATION& RFI RESPONSES Infra & EnterprlH Strvlces 4,688 47 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Security and Compliance 6,591 62 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES Trana Regulatory Support 20,991 260 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES TOTAL ESI WAGES 1,303,158 19,406 ESI EMPLOYEE BENEFITS & TAXES 407,159 9 TOTAL ESI PAYROLL. BENEFITS & TAXES 1,710,318 44 Exhibit MPC-SD-2 Docket No. 39896 Page 1 of1 ESI PAYROLL, BENEFITS, AND TAXES CHARGED TO ETI BY AFFILIATE CLASS 14,803 0.87% ENERGY AND FUEL MANAGEMENT 108401 6.34% DISTRIBUTION OPERATIONS 29,971 1.75% FINANCIAL SERVICES 183,291 10.72% FEDERAL PRG AFFAIRS 6,718 0.39% TAX SERVICES 82,495 4.82% HUMAN RESOURCES 108,108 6.32% FOSSIL PLANT OPERATIONS 25,831 1.51% INTERNAL & EXTERNAL COMMUNICATIONS 2,483 0.15% SUPPLY CHAIN 12,428 0.73% REGULATORY SERVICES 887,801 51.91% TRANSMISSION OPERATIONS 27,549 1.61% TREASURY OPERATIONS 34,842 2.04% ADMINISTRATION 1,867 0.11% LEGAL SERVICES 101,713 5.95% CUSTOMER SERVICE OPERATIONS 30,225 1.77% RETAIL OPERATIONS 3,619 0.21% OTHER EXPENSES 48,174 2.82% 1,710,318 100.00% 10 45 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 40295 ETI Exhibit No. 5 SOAH DOCKET NO. XXX-XX-XXXX DOCKET NO. 40295 APPLICATION OF ENTERGY § BEFORE THE STATE OFFICE TEXAS, INC. FOR RATE CASE § EXPENSES PERTAINING TO § OF PUC DOCKET NO. 39896 § § ADMINISTRATIVE HEARINGS SUPPLEMENTAL DIRECT TESTIMONY OF MICHAEL P. CONSIDINE ON BEHALF OF ENTERGY TEXAS, INC. OCTOBER 2012 ENTERGY TEXAS, INC. SUPPLEMENTAL DIRECT TESTIMONY OF MICHAEL P. CONSIDINE DOCKET NO. 40295 TABLE OF CONTENTS I. Witness Introduction 1 II. Purpose of Supplemental Testimony 1 Ill. Update Regarding Internal Rate Case Expenses 2 IV. Recovery of Rate Case Expenses 5 EXHIBITS Exhibit MPC-SD-3 Requested Rate Case Expenses Exhibit MPC-SD-4 ES! Payroll, Benefits, and Taxes Charged to ETI by Affiliate Class 2 Entergy Texas, Inc. Page 1of6 Supplemental Direct Testimony of Michael P. Considine Docket No. 40295 1 I. WITNESS INTRODUCTION 2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 3 A. My name is Michael P. Considine. My business address is 425 West 4 Capitol Avenue, Little Rock, Arkansas 72201. I am employed by Entergy 5 Services, Inc. ("ESI"), the service company affiliate of Entergy Texas, Inc. 6 ("ETI" or the "Company'') as a Manager in the Regulatory Accounting 7 Department. 8 9 Q. DID YOU PREVIOUSLY FILE TESTIMONY RELATED TO THIS 10 PROCEEDING? 11 A. Yes. In Docket No. 39896, I filed direct testimony as part of the 12 Company's rate filing package, supplemental direct testimony on March 13 13, 2012, and rebuttal testimony on April 13, 2012. 14 15 II. PURPOSE OF SUPPLEMENTAL DIRECT TESTIMONY 16 Q. WHAT IS THE PURPOSE OF THIS ADDITIONAL SUPPLEMENTAL 17 DIRECT TESTIMONY? 18 A. This supplemental direct testimony supports and updates the Company's 19 request to recover rate case expenses associated with this proceeding. 20 Specifically, I provide the levels of rate case expenses incurred and paid 21 as of August 31, 2012, related to outside accounting services, outside 22 legal counsel, and outside consultants ("external rate case expenses"). I 23 also provide the levels of rate case expenses incurred and paid as of Entergy Texas, Inc. Page 2 of6 Supplemental Direct Testimony of Michael P. Considine Docket No. 40295 1 August 31, 2012, related to ETI direct expenses and ESI payroll, benefits, 2 and taxes ("internal rate case expenses"). In addition, I address the 3 reasonableness and necessity of the internal rate case expenses. 4 Company witness Stephen Morris has filed direct testimony as part of 5 ETl's filing package, supplemental direct testimony on March 13, 2012, 6 and additional supplemental direct testimony contemporaneous with the 7 filing of this testimony addressing the reasonableness and necessity of 8 external rate case expenses. 9 10 Ill. UPDATE REGARDING INTERNAL RATE CASE EXPENSES 11 Q. SINCE FILING ITS RATE FILING PACKAGE, HAS THE COMPANY 12 PROVIDED ITS INCURRED RATE CASE EXPENSES? 13 A. Yes. On February 21, 2012, in response to Staff Request for Information 14 ("RF!") 9-1, the Company filed schedules of: (1) external rate case 15 expenses as of December 31, 2011; and (2) internal rate case expenses 16 as of December 31, 2011. On March 13, 2012, an update to Staff RFI 9-1 17 was provided. The Company filed schedules of (1) external rate case 18 expenses as of January 31, 2012; and (2) internal rate case expenses as 19 of January 31, 2012. Entergy Texas, Inc. Page 3 of6 Supplemental Direct Testimony of Michael P. Considine Docket No. 40295 1 Q. DO YOU PROVIDE AN UPDATE REGARDING THE LEVELS OF 2 INCURRED RATE CASE EXPENSES IN THIS PIECE OF 3 SUPPLEMENTAL DIRECT TESTIMONY? 4 A. Yes. The summary rate case expense spreadsheet included as part of 5 the Company's Second Addendum to its response to Staff RFI 9-1 is 6 attached as Exhibit MPC-SD-3, which presents external rate case 7 expenses by vendor and internal rate case expenses by ETI direct 8 expense category and ESI department. As shown in Exhibit MPC-SD-3, 9 as of August 31, 2012, the Company had incurred $3,846,734 in external 10 rate case expenses and $4,791,370 in internal rate case expenses. The 11 Company requests recovery of these external and internal rate case 12 expenses. 13 14 Q. HAVE YOU REVIEWED THE INTERNAL RATE CASE EXPENSES 15 PRESENTED IN EXHIBIT MPC-SD-3 TO DETERMINE WHETHER SUCH 16 EXPENSES ARE REASONABLE AND NECESSARY? 17 A. Yes. 18 19 Q. HOW DID YOU DETERMINE WHETHER THE INCURRED INTERNAL 20 RATE CASE EXPENSES PRESENTED IN EXHIBIT MPC-SD-3 WERE 21 REASONABLE AND NECESSARY? 22 A. Internal rate case expenses are all captured in Project Code 23 F5PPETX011. The project code is used only for time and expense related Entergy Texas, Inc. Page4 of6 Supplemental Direct Testimony of Michael P. Considine Docket No. 40295 1 to the Docket No. 39896 rate case, and all costs incurred by ESI in this 2 project code are directly billed to ETI. The process through which costs 3 are billed to project codes were described in Company witness Stephanie 4 8. Tumminello's direct testimony from Docket No. 39896. In addition, the 5 Company's affiliate class witnesses from Docket No. 39896, including 6 those who address the ETI direct charges, explained how the budgeting 7 and cost control processes work within their business units. For example, 8 timesheet and expense reports are reviewed by supervisors to ensure 9 accuracy. Also, in Docket No. 39896, Company witness Kevin G. Gardner 1O supported the reasonableness and necessity of the compensation and 11 benefits paid to ESI employees. 12 In Docket No. 39896, Company witnesses presented direct 13 testimony regarding the various classes of affiliate costs that ETI received 14 from ES!, and my Exhibit MPC-SD-4 shows the ESI rate case charges to 15 ETI by affiliate class. The processes and practices described in the 16 Company's Docket No. 39896 direct testimony regarding billing, 17 budgeting, cost control, compensation, and benefits remain in effect today. 18 These processes and practices help to ensure that the requested internal 19 rate case expenses are necessary and reasonable, represent the actual 20 costs of the services, do not include prohibited expenses, do not include 21 charges for duplicative services or expenses, and are no higher than the 22 prices charged to other affiliates, or to non-affiliates, for the same or 23 similar classes of item. Entergy Texas, Inc. Page 5 of6 Supplemental Direct Testimony of Michael P. Considine Docket No. 40295 1 Further, a review of the Company's requested rate case expenses 2 is undertaken to determine that only appropriate charges are included in 3 the rate case expense request, and inappropriate charges, such as 4 charges for luxury items or excessive meals charges, are excluded. 5 6 Q. WHAT DID YOU CONCLUDE WITH RESPECT TO THE 7 REASONABLENESS AND NECESSITY OF THE COMPANY'S 8 INCURRED INTERNAL RATE CASE EXPENSES? 9 A. Based on my review and analysis, as described above, the Company's 10 incurred internal rate case expenses are reasonable and necessary. 11 12 IV. RECOVERY OF RATE CASE EXPENSES 13 Q. HOW DOES THE COMPANY PROPOSE TO RECOVER RATE CASE 14 EXPENSES? 15 A. As explained in my direct testimony, the Company proposes that it be 16 permitted to recover all incurred rate case expenses over a three-year 17 period, with a return on the unamortized balance. 18 19 Q. WILL THE COMPANY PROVIDE ADDITIONAL UPDATES REGARDING 20 THE LEVEL OF INCURRED RATE CASE EXPENSES? 21 A. Yes. ET! will provide the next update through September 30, 2012 to Staff 22 RFI 9-1 on or around October 25, 2012. ... ---· ------------ Entergy Texas, Inc. Page 6of6 Supplemental Direct Testimony of Michael P. Considine Docket No. 40295 1 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL DIRECT 2 TESTIMONY? 3 A. Yes. 8 ENTERGY TEXAS, INC. Exhibit MPC..S0-3 RATE CASE EXPENSES PAID AND ACCRUED THROUGH THE MONTH ENDED AUGUST 31, 2012 Docket No. 40295 ETI 6/30/1 i COS DOCKET 39896 RATE CASE EXPENSES Page 1 of 2 AMOUNT ACCOUNTING DELO!TTE & TOUCHE LLP Total 915,970 LESS: NON-CONFORMING D&T EXPENSES (2,373) PRICEWATERHOUSE COOPERS LLP Total 122,168 LESS: NON-CONFORMING PWC EXPENSES (7) ACCOUNTING TOTAL 1,035,758 • CONSULTANTS DOLORES S STOKES DBA D STOKES CONSULTING 17,290 EXPERT POWERHOUSE LLC DBA EXPERGY 172,752 FINANCOINC 125,220 GERALD W TUCKER CPA 116,119 JAY HARTZELL 12,825 MILLER & CHEVALIER CHARTERED 19,443 TOWERS WATSON PENNSYLVANIA INC 2,288 LESS: NON-CONFORMING TWP EXPENSES (22) CONSULTANTS TOTAL 465,915 * DUGGINS WREN MANN & ROMERO LLP 2,345,127 LESS: NON-CONFORMING DWMR EXPENSES (66) LEGAL TOTAL 2,345,061 • INTERNAL RATE CASES EXPENSES (NON-PAYROLL) Business Meals/Entertainment 3,852 Cities Bills-Lawton Law Finn 1,117,309 Computer & Office Supplies 758 Court Transcripts 38,466 Depreciation & Amort Expenses 204,136 Employee Mtgs/Functions 7,762 Legal Notices 100,799 Lodging 18,959 Other Employee Expenses 3,423 Other Office & General 5,829 Pagers/Cellular Phones 10 Personal Car Mileage • Local 2,764 Postage and Overnight Delivery 8,699 Printing, Mailing & Shipping 12,601 Safely Training Loader i,843 Service Company Recipient 342,078 Temporary Services 66,943 Travel Transportation 24,126 Utility Bills 2,518 LESS: NON-CONFORMING COMPANY EXPENSES (560) INTERNAL RATE CASES EXPENSES (NON-PAYROLL) TOTAL i,962,315 ESI PAYRQLL. BENEFITS & TAXES 2,829,056 See next tab and Ex. MPL-SD-4 for Detail RATE CASE EXPENSES THROUGH S/31112 8,638,105 *Please refer to the Company's response and addenda to Staff 9-1 for detail supporting the Accounting, Consultant, and Legal expenses addressed above. Amounts for Duggins Wren Mann & Romero, lLP include fees and expenses from the following consultants: Commonwealth Consulting; Alliance Consulting; Lewis & Ellis; Naman, Howell, Smith & Lee; and Vector Advisors. ENTERGY TEXAS, INC. RATE CASE PAYROLL FOR ESI EMPLOYES THROUGH AUGUST 31, 2012 ETI 6130111 COS DOCKET 39a96 Exhibit MPC·S0-3 Docket No. 40295 DEPARTMENT WAGES HOURS ACTIVITIES Page 2 of 2 frnr, crp-·AVin, secui- & R.E. op-·· ..... "14' ASSIST IN RATE CASE PREPARATION & RFI RESPONSES icoueciions. E"siDetai1 •· ....... 14 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES f ... -· .. ------ "''" .. . ....... ·--·- r.Remittance ...... _ ......-.Processing-Esi - __ .. ... ... 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RESPONSES ' r~:::i~::t6~~~$~~:~l~:r~'!f ~--~ lReguiiiT,:Y71ffrSiEnergy Seillmt - - ... - ·- -...... . .,- i~ 2."" -==-~~:i ~~~:~; :~ ~~~ g~~~ :~~:~:~:~~: ::: :~~:g~~~~ 05 i57,592 ----""2,47ii) ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 'sPo comlian"Ce&coiilract Admiii~ -- 1·.~~~J-~----=~;~1, ~~~:~~ :~ :~~ :;~~~ ::~:~~~~:g~ ! ~;: ~~;:g~;~~ ··- ..... =:J~_,2_?9, -- - _fcj_i ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 3,016 29 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES !§1?..~rati~~:>,£'.'~'.li°ii~~- _: ~--.. . -· -l,000 - "'121 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 1Supply Planning andAnalysis 742 ....... ---- "' 15 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES !'Power SuPply -.... .. ... ··········· ... j" -- .,\1 'f•?..8~ .. ::=~ Ji,:i_~)l ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ~i ASSIST IN RATE CASE PREPARATION & RFI . lVPEnorgy"ivlSiiai;iemanf : 487 RESPONSES r~:J;~~;t~~~~--=-= = .. . - ---t !~:;~~- ~-- -~ . 1~~1 ~~~:~~ :~ ~~~ ~~~~ :~~:~~;:~~: ::: :~~:g~~~~ ... tt~!r~ ~~'.eipii_i;~-~~r.'!i;:~s .... _ .. + 4- -~- ... =-=-~1 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES lSecurity and Compliance . ... 61l ASSIST IN RATE CASE PREPARATION & RFI RESPONSES l"rrans ~~u!ii~) - - - - - - - - - - - - - - - - - · - - - - - - l > - - - - - - - · - - - - - - - - - - - -........ ~---· * ET! em lo ees with affiliate costs SOAH Docket No. XXX-XX-XXXX PUC Docket No. 40295 SOAH DOCKET NO. XXX-XX-XXXX DOCKET NO. 40295 APPLICATION OF ENTERGY § TEXAS, INC. FOR RATE CASE § EXPENSES PERTAINING TO § OF PUC DOCKET NO. 39896 § § ADMINISTRATIVE HEARINGS SUPPLEMENTAL DIRECT TESTIMONY OF MICHAEL P. CONSIDINE ON BEHALF OF ENTERGY TEXAS, INC. OCTOBER 25, 2012 ENTERGY TEXAS, INC. SUPPLEMENTAL DIRECT TESTIMONY OF MICHAEL P. CONSIDINE DOCKET NO. 40295 TABLE OF CONTENTS I. Witness Introduction 1 II. Purpose of Supplemental Direct Testimony 1 Ill. Update Regarding Internal Rate Case Expenses 2 IV. Recovery of Rate Case Expenses 5 EXHIBITS Exhibit MPC-SD-5 Summary Rate Case Expense Spreadsheet Exhibit MPC-SD-6 ES! Rate Case Charges to ETI by Affiliate Class 2 Entergy Texas, Inc. Page 1of5 Supplemental Direct Testimony of Michael P. Considine Docket No. 40295 1 I. WITNESS INTRODUCTION 2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 3 A. My name is Michael P. Considine. My business address is 425 West 4 Capitol Avenue, little Rock, Arkansas 72201. I am employed by Entergy 5 Services, Inc. ("ESI"), the service company affiliate of Entergy Texas, Inc. 6 ("ETI" or the "Company") as a Manager in the Regulatory Accounting 7 Department. 8 g Q. ARE YOU THE SAME MICHAEL P. CONSIDINE THAT PREVIOUSLY 10 FILED TESTIMONY IN BOTH DOCKET NO. 39896 AND THIS DOCKET? 11 A. Yes. 12 13 II. PURPOSE OF SUPPLEMENTAL DIRECT TESTIMONY 14 Q. WHAT IS THE PURPOSE OF THIS ADDITIONAL SUPPLEMENTAL 15 DIRECT TESTIMONY? 16 A. This supplemental direct testimony supports and updates the Company's 17 request to recover rate case expenses associated with this proceeding. 18 Specifically, I provide the levels of rate case expenses incurred and paid 19 as of September 30, 2012, related to outside accounting services, outside 20 legal counsel, and outside consultants ("external rate case expenses"). I 21 also provide the levels of rate case expenses incurred and paid as of 22 September 30, 2012, related to ETI direct expenses and ESI payroll, 23 benefits, and taxes ("internal rate case expenses"). in addition, I address Entergy Texas, Inc. Page 2 of 5 Supplemental Direct Testimony of Michael P. Considine Docket No. 40295 1 the reasonableness and necessity of the internal rate case expenses paid 2 in September 2012. Company witness Stephen Morris has filed direct and 3 supplemental direct testimony in Docket No. 39896 and supplemental 4 direct testimony in this docket on October 5, 2012 and contemporaneous 5 with the filing of this testimony addressing the reasonableness and 6 necessity of external rate case expenses. 7 8 Ill. UPDATE REGARDING INTERNAL RATE CASE EXPENSES g Q. SINCE FILING ITS RATE FILING PACKAGE, HAS THE COMPANY 10 PROVIDED ITS INCURRED RATE CASE EXPENSES? 11 A Yes. On February 21, 2012, in Docket No. 39896, the Company filed its 12 initial responses to Staff's 9th Requests for Information ("RFls"), including 13 schedules of internal and external rate case expenses as of December 31, 14 2011. On March 13, 2012, in Docket No. 39896, the Company filed my 15 first supplemental direct testimony with attached exhibits containing 16 schedules of internal and external rate case expenses as of January 31, 17 2012. On March 16, in Docket No. 39896, the Company provided updates 18 to its responses to Staff's 9th RFls. On October 5, in this docket, the 19 Company filed my second supplemental direct testimony with attached 20 exhibits containing schedules of internal and external rate case expenses 21 as of August 31, 2012, as well as further updates to its responses to 22 Staff's 9th RFls. ------- ------------- Entergy Texas, Inc. Page 3 of 5 Supplemental Direct Testimony of Michael P. Considine Docket No. 40295 1 Q. DO YOU PROVIDE AN UPDATE REGARDING THE LEVELS OF 2 INCURRED RATE CASE EXPENSES IN THIS PIECE OF 3 SUPPLEMENTAL DIRECT TESTIMONY? 4 A Yes. The summary rate case expense spreadsheet, included as part of 5 the Company's third addendum to its response to Staff RF! 9-1 and filed 6 contemporaneously herewith, is attached as Exhibit MPC-SD-5. This 7 exhibit presents external rate case expenses by vendor and internal rate 8 case expenses by ETI direct expense category and ES! department. As 9 shown in Exhibit MPC-SD-5, as of September 30, 2012, the Company had 10 incurred $3,908,214 in external rate case expenses and $4,844,362 in 11 internal rate case expenses. The Company requests recovery of these 12 rate case expenses. 13 14 Q. HAVE YOU REVIEWED THE INTERNAL RATE CASE EXPENSES 15 PRESENTED IN EXHIBIT MPC-SD-5 TO DETERMINE WHETHER SUCH 16 EXPENSES ARE REASONABLE AND NECESSARY? 17 A Yes. 18 19 Q. HOW DID YOU DETERMINE WHETHER THE INCURRED INTERNAL 20 RATE CASE EXPENSES PRESENTED IN EXHIBIT MPC-S0-5 WERE 21 REASONABLE AND NECESSARY? 22 A Internal rate case expenses are all captured in Project Code 23 F5PPETX011. The project code is used only for time and expense related Entergy Texas, Inc. Page4 of 5 Supplemental Direct Testimony of Michael P. Considine Docket No. 40295 1 to the Docket No. 39896 rate case, and all costs incurred by ESI in this 2 project code are directly billed to ET!. The process through which costs 3 are billed to project codes were described in Company witness Stephanie 4 B. Tumminello's direct testimony from Docket No. 39896. In addition, the 5 Company's affiliate class witnesses from Docket No. 39896, including 6 those who address the ETI direct charges, explained how the budgeting 7 and cost control processes work within their business units. For example, 8 timesheet and expense reports are reviewed by supervisors to ensure 9 accuracy. Also, in Docket No. 39896, Company witness Kevin G. Gardner 10 supported the reasonableness and necessity of the compensation and 11 benefits paid to ESI employees. 12 In Docket No. 39896, Company witnesses presented direct 13 testimony regarding the various classes of affiliate costs that ETI received 14 from ES!, and my Exhibit MPC-SD-6, attached hereto, shows the ESI rate 15 case charges to ETI by affiliate class. The processes and practices 16 described in the Company's Docket No. 39896 direct testimony regarding 17 billing, budgeting, cost control, compensation, and benefits remain in 18 effect today. These processes and practices help to ensure that the 19 requested internal rate case expenses are necessary and reasonable, 20 represent the actual costs of the services, do not include prohibited 21 expenses, do not include charges for duplicative services or expenses, 22 and are no higher than the prices charged to other affiliates, or to non- 23 affiliates, for the same or similar classes of item. Entergy Texas, Inc. Page 5 of 5 Supplemental Direct Testimony of Michael P. Considine Docket No. 40295 1 Further, a review of the Company's requested rate case expenses 2 is undertaken to determine that only appropriate charges are included in 3 the rate case expense request, and inappropriate charges, such as 4 charges for luxury items or excessive meals charges, are excluded. 5 6 Q. WHAT DID YOU CONCLUDE WITH RESPECT TO THE 7 REASONABLENESS AND NECESSITY OF THE COMPANY'S 8 INCURRED INTERNAL RATE CASE EXPENSES? 9 A Based on my review and analysis, as described above, the Company's 10 incurred internal rate case expenses are reasonable and necessary. 11 12 IV. RECOVERY OF RATE CASE EXPENSES 13 Q. HOW DOES THE COMPANY PROPOSE TO RECOVER RATE CASE 14 EXPENSES? 15 A As explained in my direct testimony, the Company proposes that it be 16 permitted to recover all incurred rate case expenses over a three-year 17 period, with a return on the unamortized balance. 18 19 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL DIRECT 20 TESTIMONY? 21 A Yes. ENTERGY TEXAS, !NC. exhibit MPC-S0-5 Docket No. 40295 RATE CASE EXPENSES PAID AND ACCRUED THROUGH THE MONTH ENDED SEPTEMBER 30, 2012 Page 1 of2 ETI 6/30/11 COS DOCKET 39896 RATE CASE EXPENSES AMOUNT ACCOUNTING DELOITTE & TOUCHE LLP Total 915,970 LESS NON-CONFORMING D&T EXPENSES (2,373) PRICEWATERHOUSE COOPERS LLP Total 122,168 LESS NON-CONFORMING PWC EXPENSES (7} ACCOUNTING TOTAL 1,035,756 • !,';ONSULTft,NI~ DOLORES S STOKES DBA D STOKES CONSULTING 17,290 EXPERT POWERHOUSE LLC DBA EXPERGY 172,752 FINANCO INC 125,220 GERALD W TUCKER CPA 116,119 JAY HARTZELL 12,625 MILLER & CHEVALIER CHARTERED 19,443 TOWERS WATSON PENNSYLVANIA INC 2,288 LESS· NON-CONFORMING TWP EXPENSES (22) CONSULTANTS TOTAL 465,915 • DUGGINS WREN MANN & ROMERO LLP 2,406,607 LESS NON-CONFORMING DWMR EXPENSES (66} LEGAL TOTAL 2,406,541 • INTERNAL BATE CASES EXPENSES (NQN-PAYRQU,} Business Meals/Entertainment 3,852 Cities Bills-Lawton Law Firm 1, 117,309 Computer & Office Supplies 758 Court Transcripts 38,466 Depreciation & Amort Expenses 207,683 Employee Mtgs/Functions 7,762 Legal Notices 100,799 Lodging 18,959 Other Employee Expenses 3,423 Other Office & General 5,829 Pagers/Cellular Phones 10 Personal Car Mileage • Local 2,764 Postage and Overnight Delivery 8,699 Pnnting, Mailing & Shipping 12,601 SerY1ce Company Recipient 346,MO Temporary Services 66,943 Travel Transportation 24, 126 Utility Bills 2,518 LESS NON-CONFORMING COMPANY EXPENSES (560) INTERNAL RATE CASES EXPENSES (NON-PAYROLL) TOTAL 1,968,581 ES! PAYROLL. BENEFITS & TAXES 2,875,781 See next tab and Ex. MPL-SD-6 for Detail BATE CASE !iXPEN§ES THRO!,IGH 9130112 8,752,576 •Please refer to the Company's response and addenda to Staff 9-1 · for detail supporting the Accounting, Consultant, and Legal expenses addressed above. Amounts for Duggins Wren Mann & Romero, LLP include fees and expenses from the following consultants: Commonwealth Consulting; Alliance Consulting; Lewis & Ellis; Naman, Howell, Smith & Lee; and Vector Advisors. ENTERGY TEXAS, INC. RATE CASE PAYROLL FOR ES! 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RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN RATE CASE PREPARATION & Rf! RESPONSES ASSIST IN RATE CASE PREPARATION & Rf! RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN RATE CASE PREPARATION & RF! RESPONSES (133) ASSIST IN RATE CASE PREPARATION & RF! RESPONSES ·-==~~~ ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 1001 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES -~--4~ ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ·-···'"''"'44 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES -··'"'-~~, ASSIST IN RATE CASE PREPARATION & RF! RESPONSES ···-···--,,.3..~.8-J q TOTAL ES! WAGES 2,102,309 32,592 Affiliate Rate Case Expenses Exhibit MPC-SD-6 Payroll, Benefits, Payroll Taxes, and Incentive Costs by Class Docket No. 40295 Through Sept 30, 2012 Page 1of1 -+-------·-·-· · · - - - - - - ·..·· * ET! em lo ees with affiliate costs \0 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 40295 ETI Exhibit No. 7 SOAH DOCKET NO. XXX-XX-XXXX PUCT DOCKET NO. 40295 APPLICATION OF ENTERGY § BEFORE THE STATE OFFICE TEXAS, INC. FOR RATE CASE § OF EXPENSES PERTAINING TO § ADMINISTRATIVE HEARINGS PUC DOCKET NO. 39896 § RE BUTTAL TESTIMONY -- ~ !"'.:. :;e. -< ... <..'""' ~.-.::. OF ~·- ' f -- c..n ' ( ·-0 "' ',- :;).':. ,, 4, ;.t r:-? J C" Cf) MICHAEL P. CONSIDINE ON BEHALF OF ENTERGY TEXAS, INC. NOVEMBER 15, 2012 ENTERGY TEXAS, INC. REBUTTAL TESTIMONY OF MICHAEL P. CONSIDINE PUCT DOCKET NO. 40295 TABLE OF CONTENTS Page I. WITNESS INTRODUCTION 1 II. PURPOSE OF REBUTTAL TESTIMONY 1 m. REBUTTAL ISSUES 2 A. Allocation of Rate Case Expenses 2 B. Return 011 the Unamortized Balance 3 C. Frequency of Rate Cases 4 D. Calpine-Carville PPA 5 E. Costs Billed by Company Consultant Gerald Tucker 7 F. Depreciation 9 EXHIBITS MPC-R-1: Excerpts from ETl's Response to Staff 9-1, Addendum 3 Entergy Texas, Inc. Page 1of11 Rebuttal Testimony of Michael P. Considine PUCT Docket No. 40295 1 I. WITNESS INTRODUCTION 2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 3 A. My name is Michael P. Considine. My business address is 425 West 4 Capitol Avenue, little Rock, Arkansas 72201. I am employed by Entergy 5 Services, Inc. ("ESI"), the service company affiliate of Entergy Texas, Inc. 6 ("ETI" or the "Company") as a Manager in the Regulatory Accounting 7 Department I was formerly a Senior Staff Accountant in the Regulatory 8 Accounting Department during Docket No. 39896. As a Manager in 9 Regulatory Accounting, I am responsible for managing the work of those 1O gathering, preparing, and analyzing accounting data for the Operating 11 Companies for use in preparing rate filings. This includes coordination of 12 accounting-related schedules and testimony filed with the various 13 regulatory commissions that have jurisdiction over the Operating 14 Companies. 15 16 Q. ARE YOU THE SAME MICHAEL P. CONSIDINE THAT PREVIOUSLY 17 FILED TESTIMONY IN BOTH DOCKET NO. 39896 AND THIS DOCKET? 18 A. Yes. 19 20 II. PURPOSE OF REBUTTAL TESTIMONY 21 Q. WHAT IS THE PURPOSE OF THIS REBUTTAL TESTIMONY? 22 A. The purpose of my rebuttal testimony is to respond to various issues 23 raised in Staff and Intervenor Direct Testimonies and Recommendations Entergy Texas, Inc. Page 2ofi1 Rebuttal Testimony of Michael P. Considine PUCT Docket No. 40295 1 related to the Company's request to recover Docket No. 39896 rate case 2 expenses associated with various aspects including issues related to the 3 Company's request to recover internal rate case expenses. The rebuttal 4 testimony of witness Stephen F. Morris addresses certain aspects of those 5 same filings including issues related to outside legal counsel and outside 6 accounting and consulting firms ("external rate case expenses"). 7 8 !IL REBUTTAL ISSUES 9 A. Allocation of Rate Case Exgenses 10 11 Q. PLEASE ADDRESS STAFF'S APPROACH TO THE ALLOCATION OF 12 RATE CASE EXPENSES. 13 A. Staff Witness Brian Murphy recommends a class revenue requirement 14 allocator based upon each class' Commission-approved revenue 1 15 requirement. Mr. Murphy recommends that ETl's Schedule RCE-2 rates 16 be set in the compliance phase of this proceeding by multiplying the 17 approved total amount by Staffs recommended class allocator and 18 dividing the resulting class share both by ETl's proposed three-year 19 amortization period and also by ETl's proposed class billing determim.mts. 2 20 Mr. Murphy also recommends that the Company be required to track 21 collection on Rider RCE and terminate billing in the billing month in which 22 the approved amount has been billed. 1 Murphy Direct at 4. 2 Id. at 5. Entergy Texas, Inc. Page 3of11 Rebuttal Testimony of Michael P. Considine PUCT Docket No. 40295 1 Q. DOES ETI OBJECT TO STAFF'S ALLOCATION BASIS? 2 A. No, ETI does not object to Staff's approach on allocation. 3 4 Q. DOES THE COMPANY OBJECT TO TRACKING AND TERMINATING 5 THE RIDER ONCE THE APPROVED AMOUNT HAS BEEN BILLED? 6 A. The Company agrees with this approach so long as the final order 7 includes language following Commission precedent allowing the Company 8 to seek recovery of any additional rate case expenses accrued after 9 September 30, 2012 in its subsequent rate case. 3 10 11 B. Retum on the Unamortized Balance 12 Q. PLEASE DESCRIBE STAFF'S RECOMMENDATION FOR THE RETURN 13 ON THE UNAMORTIZED BALANCE. 14 A. Staff's Recommendations suggest that ET! not be allowed to recover any 15 return on the unamortized balance as the Company had requested for the 16 three-year period over which ETI would be recovering the approved rate 17 case expenses. 18 19 Q. WHAT IS YOUR VIEW ON THE RETURN ON THE UNAMORTIZED 20 BALANCE? 3 Requests for Rate Case Expenses Severed From Docket No. 38339 (Application of CenterPoint Energy Houston Electric, LLC for Authority to Change Rates), Docket No. 39127, Order, Finding of Fact 26 (Jun. 6, 2011). Entergy Texas, Inc. Page 4of11 Rebuttal Testimony of Michael P. Considine PUCT Docket No. 40295 1 A The return is a necessary component of a cost that is amortized over a 2 period of time. It represents the time value of money and the cost of the 3 Company's lost opportunity to deploy those funds elsewhere. The 4 Company's proposal reflects a reasonable balancing of interests on this 5 issue as the Company is only proposing a return over the three-year 6 recovery period and does not propose to recover the lost opportunity costs 7 on the rate case expenses from the time they were incurred. If the 8 Company is not permitted to recover a return on the unamortized portion 9 of its approved rate case expenses, it will, in effect, incur a disal!owance 10 relative to the amount of rate case expenses approved by the 11 Commission. Therefore, I disagree with Staff's recommendation on this 12 point; the Company should be allowed to recover its return on the 13 unamortized balance. 14 15 C. Frequency of Rate Cases 16 Q. PLEASE SUMMARIZE THE POLICY ISSUES RAISED BY PARTIES 17 REGARDING THE FREQUENCY OF RATE CASES. 18 A. Both the State Agencies in their Recommendations, and OPUC witness 19 Nathan Benedict point to the frequency of rate cases as a reason the 20 Commission should disallow otherwise reasonable rate case expenses. 21 Mr. Benedict asserts that the Company has filed three base rate cases in 22 a little more than four years and that this frequency places a burden on 23 ratepayers. The State Agencies claim that frequent requests for rate relief Entergy Texas, Inc. Page 5of11 Rebuttal Testimony of Michael P. Considine PUCT Docket No. 40295 1 for electric utilities are shareholder-driven and because of that, half of rate 2 case expenses should be paid for by the shareholders. 3 4 Q. DO YOU AGREE WITH THE ARGUMENTS MADE REGARDING THE 5 FREQUENCY OF BASE RATE CASES? 6 A. No. Rate cases are cost-driven. The Company is permitted to recover its 7 reasonable and necessary costs and to have the opportunity to earn a 8 reasonable retum cm invested capita!. Each of ETl's recent base rate g cases has resulted in a rate increase for the Company. Ironically, the 10 Company has proposed on multiple occasions to establish rate riders to 11 address the Company's rising costs that would substantially reduce the 12 likelihood of the Company filing rate cases as frequently as it has in the 13 last few years. These proposals have been opposed by the same parties 14 who here complain about the frequency of rate cases. Without the ability 15 to recover the increasing level of reasonable expenses through such 16 riders, a utility is left with no recourse but to file a rate case. 17 18 D. Calpine-Carville PPA 19 Q. PLEASE DESCRIBE OPUC'S RECOMMENDATIONS REGARDING THE 20 CALPINE-CARVILLE PURCHASED POWER AGREEMENT. 21 A. In its Recommendation and Request for Hearing, OPUC proposes that the 22 Commission disallow the recovery of rate case expenses relating to the 23 regulatory approval of this purchased power agreement ("PPA"). OPUC Entergy Texas, Inc. Page6of11 Rebuttal Testimony of Michael P. Considine PUCT Docket No. 40295 1 states that the Company has already been granted recovery of costs 2 associated with the regulatory approval process for the Calpine-Carville 3 PPA and the Company sought and obtained that regulatory approval in 4 Docket No. 39896. Thus, it claims that if the Company were to also 5 recover those costs as part of its rate case expenses in this docket, it 6 would constitute double recovery. Specifically, OPUC mentioned a 7 disallowance of the portion of the expenses related to the testimonies of 8 Company witness Robert Cooper and the billable time of Company 9 attorney Dick Westerburg. 10 11 Q. WHAT IS YOUR RESPONSE TO THE DISALLOWANCES SUGGESTED 12 BY OPUC REGARDING THE CALPINE~CARVILLE PPA? 13 A. OPUC fails to recognize an important distinction between the amounts at 14 issue. An individual may have charged time to Project Code 15 F3PPWET308 (that is, the internal project code for the Calpine PPA 16 development costs) as the Calpine PPA was being developed, including 17 time spent determining how regulatory approval of the PPA might 18 generally be obtained and designing the PPA in a manner that would 19 facilitate such approval. These costs would have occurred during the test 20 year and were included for recovery in Docket No. 39896. However, an 21 individual may have also charged time to Project Code F5PPETX011 (that 22 is, the internal project code for the rate case filed by ETI in Docket No. 23 39896) as they developed testimony specifically for Docket No. 39896 or Entergy Texas, Inc. Page 7of11 Rebuttal Testimony of Michael P. Considine PUCT Docket No. 40295 1 responded to RFls related to the Calpine PPA during the course of the 2 rate case. These costs would have occurred after the test year. Recovery 3 of these latter costs was severed from Docket No. 39896 and is now being 4 requested in this docket Costs recorded to Project Code F5PPETX011 5 are the only costs the Company is proposing to recover in this instant 6 docket. Therefore, no double recovery exists. 4 7 8 E. Costs Billed by Company Consultant Gerald Tucker 9 Q. PLEASE BRIEFLY SUMMARIZE STATE AGENCIES' RECOMMENDED 10 DISALLOWANCE FOR COSTS BILLED BY COMPANY CONSULTANT 11 GERALD TUCKER. 12 A State Agencies' recommended $116, 119 disallowance is based upon 13 claims that services performed by Mr. Tucker are duplicative and go 14 beyond reviewing affiliate costs. 15 16 Q. DO YOU AGREE WITH STATE AGENCIES' CHARACTERIZATION OF 17 COSTS BILLED BY MR. TUCKER? 18 A No. Over the past two decades, the PUCT has at times disallowed large 19 percentages of utilities' affiliate expenses, including those of Entergy Gulf 20 States, Inc. ("EGSI"). One of the concerns raised in the past by the ALJs 21 and the Commission has been an inability to understand the information 4 Moreover, on pages 43-44 of her direct testimony in Docket No. 39896, Company witness Tumminello provided a detailed description of the controls and review process in affiliate billing that ensure actual costs are reflected, and the Commission disallowed no costs due to duplicative charges. Entergy Texas, Inc. Page 8of11 Rebuttal Testimony of Michael P. Considine PUCT Docket No. 40295 1 presented by the utilities. As a result, the Company needs to ensure that 2 it has experienced personnel to assist in the effective preparation and 3 presentation of its rate cases. Mr. Tucker brings a level of expertise and 4 perspective to ensure this effective preparation and presentation. He is an 5 accountant and thus brings a perspective that the Company's outside 6 counsel do not bring to a rate case. 7 Mr. Tucker has been involved in all ET! (formerly EGSI) rate cases 8 since Docket No. 16705 in 1997 as well as numerous rate cases filed by 9 other utilities in Texas. This extensive experience with ETI and its 10 previous dockets is exactly the reason Mr. Tucker was asked to assist with 11 the review of discovery as well. This review included completeness of the 12 response, consistency with responses in the current and previous cases, 13 and clarity of the response. Mr. Tucker also assisted with preparation for 14 depositions of both Company and intervenor witnesses along with the 15 preparation of Company testimony and rate filing package schedules. 16 With Mr. Tucker's assistance, the Company is better able to provide the 17 information in a clear and accurate manner that allows customer 18 representatives to analyze the Company's costs and requested rates. 19 Likewise, Mr. Tucker's assistance has been necessary to ensure, to the 20 extent possible, that ETl's affiliate charges, in particular, are not 21 susceptible to the substantial affiliate cost disallowance that was ordered /0 Entergy Texas, Inc. Page 9of11 Rebuttal Testimony of Michae! P. Considine PUCT Docket No. 40295 1 in Docket No. 16705.5 There are very few individuals who have as much 2 rate case experience with the Company as does Mr. Tucker, and there are 3 no employees at the Company or ESI who have Mr. Tucker's experience 4 with and knowledge of how other Texas utilities present their affiliate costs 5 and other rate case matters. 6 6 7 F. Depreciation 8 Q. PLEASE DESCRIBE THE STATE AGENCIES' RECOMMENDED 9 DISALLOWANCES FOR DEPRECIATION. 10 A. The State Agencies' reason for disallowing $207 ,683 is that there is no 11 evidence to prove the reasonableness and necessity of this charge as a 12 cost of participation in the base rate case. The State Agencies claim that 13 the "attached detail" referenced in the summary spreadsheet was not 14 attached. 15 16 a. HOW DO YOU RESPOND TO THE STATE AGENCIES' CLAIMS? 17 A. The State Agencies are wrong. The detail State Agencies claims is 18 lacking was in fact provided in the very RFI response State Agencies cites 19 as deficient, ETl's response to Staff 9-1, Addendum 3. Accordingly, I have 20 attached as Exhibit MPC-R-1 those portions of the Company's voluminous 5 In Docket No. 16705, all of Entergy Services, lnc.'s affiliate charges to EGSI were disallowed. 6 A copy of Mr. Tucker's resume is attached to the rebuttal testimony of Stephen F. Morris as Exhibit SFM-R-2. {{ Entergy Texas, Inc. Page 10of11 Rebuttal Testimony of Michael P. Considine PUCT Docket No. 40295 1 response to Staff 9-1, Addendum 3 that contain the detail relevant to State 2 Agencies' allegation. 3 Page 1 of Exhibit MPC-R-1 is the summary spreadsheet referenced 4 by State Agencies containing the total of $207,683 for "Depreciation and 5 Amort Expense." Page 2, the second tab of the same spreadsheet, 6 provides additional information regarding the labor costs that drive the 7 depreciation and amortization expense at issue, including the segregation 8 of such labor costs by department The remaining pages of Exhibit MPC- 9 R-1 are a spreadsheet entitled "Roadmap to Internal Rate Case 10 Expenses," which breaks down each of the totals comprising the "Internal 11 Rate Case Expenses (Non-Payroll)" category addressed on the summary 12 spreadsheet on Page 1, including the depreciation and amortization 13 expense about which State Agencies complains. 7 Specifically, on Page 8 14 of Exhibit MPC-R-1, this roadmap spreadsheet breaks down the 15 depreciation and amortization total by project code, year, month, resource 16 code, resource description, monthly amount, and journal ID number. 17 Thus, contrary to State Agencies' claim, the Company provided a 18 "roadmap" of detail in support of the expense at issue. 7 ETl's Response to Staff RFI 9-1. Addendum 3 is cumulative and includes the original response to Staff RFI 9-1, Addendum 1, Addendum 2, and Addendum 3. The roadmap spreadsheet was first included in Addendum 1 and was then entitled "Guide to Internal Rate Case Expense Invoices." The same spreadsheet was updated in Addendum 2 and retitled "Roadmap to lntemc:d Rate Case Expenses" to more accurately reflect its purpose and contents. Again, every document and piece of detail provided by the Company in response to Staff RFi 9-1 was cumulatively included in Addendum 3, which State Agencies cites as lacking sufficient detail, including the original and updated version of the roadmap spreadsheet Entergy Texas, Inc. Page 11of11 Rebuttal Testimony of Michael P. Considine PUCT Docket No. 40295 1 Moreover, these costs are a reasonable and necessary part of 2 providing services. The use of assets required to support employee 3 service functions necessarily results in depreciation and amortization cost. 4 ESl's depreciation expense is thus loaded to all project codes which incur 5 ESI labor charges. The rate case project code here should likewise be 6 charged its share of depreciation expense. 7 Accordingly, State Agencies' proposed disallowance should be 8 rejected. g 10 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY? 11 A. Yes. Exhibit MPC-R-1 Docket No. 40295 Page 1 of 14 ENTERGY TEXAS, lNC. RATE CASE EXPENSES PAID AND ACCRUED THROUGH THE MONTH ENDED SEPTEMBER. 30, 2012 ET! 6/30/11 COS DOCKET 39896 RATE CASE EXPENSES STAFF DATA REQUEST9-1 ADDENDUM 3 AMOUNT • ACCOUNTING DELOlTIE & TOUCHE LLP Total 915,970 SEE ATTACHED DETAIL LESS: NON-CONFORMING D&T EXPENSES (2.373) PRlCEWATERHOUSE COOPERS Ll.P Total 122,168 SEE ATTACHED DETAIL LESS: NON·CONFORM!NG PWC EXPENSES (7) ACCOUNTING TOTAL 1,035,758 CONSUL TANT$ DOLORES S STOKES DBA D STOKES CONSUi.TiNG 17,290 SEE ATTACHED DETAIL EXPERT POWERHOUSE LLC OBA EXPERGY 172,752 SEE ATTACHED DETAIL FINANCOlNC 125,220 SEE ATTACHED DETAIL GERALD W TUCKER CPA 116,119 SEE ATTACHED DETAIL JAY HARTZELL 12,825 SEE ATTACHED DETAIL MILLER & CHEVALIER CHARTERED 19.443 SEE ATTACHED DETAIL TOWERS WATSON PENNSYLVANIA INC 2,288 SEE ATTACHED DETAIL LESS; NON·CONFORMlNG TWP EXPENSES {22) CONSULTANTS TOTAL 465,915 DUGGINS WREN MANN & ROMERO LLP 2,406,607 SEE ATTACHED DETAIL LESS: NON-CONFORMING DWMR EXPENSES (66) l.EGAL TOTAL 2,406,541 l~TERNAL RATE CASES EXPENSES !NON-PAYROJ.JJ. Business Meals/Entertainment 3,852 SEE ATTACHED DETAIL Cities BiTis·l.awton Law Firm 1, 117,300 SEE ATTACHED DETAIL Computer & Office Supplies WJ SEE ATTACHED DETAIL Court Transcripts 38,466 SEE ATTACHED DETAIL Depreciation & Amort Expenses 207,683 SEE ATTACHED DETAIL Employ$ Mtgs/Functfons 7,762 SEE ATTACHED DETAIL Legal Notices 100,799 SEE ATTACHED DETAIL Lodging 16,959 SEE ATIACHED DETAIL Other Employee Expenses 3,423 SEE ATTACHED DETAIL Other Office & General 5,1329 SEE ATTACHED DETAlL Pagers/Cellular PhOnes 10 SEE ATTACHED DETAIL Personal Car M~eage • Local 2,764 SEE ATTACHED DETAIL Postage and Overnight Delivery 13,699 SEE ATTACHED DETAIL Printing, Mailing & Shipping 12,601 SEE ATTACHED DETAIL Sefllice Company Recipient 346,640 SEE ATTACHED DETAIL Temporary Services 66,943 SEE ATTACHED DETAIL Travel Transportation 24,126 SEE ATTACHED DETAIL U!IU!y81ns 2,51!l SEE ATTACHED DETAll. LESS: NON-CONFORMING COMPANY EXPENSES (560) INTERNAL RATE CASES EXPENSES (NON-PAYROLL) TOTAL 1,968,581 ES! PAYROLL, BENEFIT§ & TAXES 2,875,781 SEE ATTACHED DETAIL f'AIE CA$E EXPENSES .I!jSQUGH 913QL12 a,752,576 -----··············--- Exhibit MPC-R-1 Docket No. 40295 Page 2of14 ENTERGY TEXAS. INC. RATE CASE PAYROLL FOR ESI EMPLOYEES THROUGH SEPTEMBER 30, :2012 Ell 6130/11 COS DOCKET 39896 STAFF DATA REQUEST 9·1 ADDENDUM:; DEPARTl/lEMT WAGES HOURS ACTIVITIES 14 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ----,,1~4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN AATE CASE PREPAAA110N & RFI RESPONSES ---=::! ASSIST IN RATE CASE PREPAAATION & RFI RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES """"""'=="""":=---------+--*.:::+-----::"1 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES i,,--__,,...:.....,,...--,,.,,,...,.-~------+-....,,..,--..=-1---~..,.i ASSIST IN RATE CASE PREPARATION & RFI RESPONSES -----1---,.,:.;;~,i......--;.:.;.:;.;: ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 4 ----+--~:.;;;;;+.--...:;::;;,;;,i ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN RATE CASE !'REPARATION & RFI RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN RATE C~E PREPARATION & Rl'l RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES --~.;.t ASSIST IN RATE:: CASE PREPARATION & RFl RESPONSES ASSIST IN RATE CASE PREPARATION & RF1 RESPONSES ASSIST tN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES · - - - - - 1 · - - r i r . t - - - " ' " " " d ASSIST IN RATE CASE PREPARATION & RF! RESPONSES ASSIST IN RAT!:: CASE PREPARATION & RFI RESPONSES --ru::,;e::l3 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 177 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ..;...;.;.;...;.._ _ _ _ _-+--,,;.:.~.:,:;+-.-......;,35d5 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES 73 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES --~ ASSIST IN RATE CASE PREPARATION & Rf'I RESPONSES ---+---..,.,~.,+---~33=5,.i ASSIST IN RATE CASE PRE!'AAATION & RF! RESPONSES 339 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES -------=t---"""14 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 1,721 22 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ;;.:.;:.:..:::..:=;;;.:..----+---1..:8.:.:.,8::;59;.!.....---29::::.i5 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 17,0BS 215 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES h--"::""-:--....,,..--------1---..-,1""4,""71'"'9+---~245 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES 5,966 45 ASSIST IN RATE CASE PREPARATION & Rl'l RESPONSES --T3Jlj(i-·--4.,.,1""4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 2,758 18 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES """'+""""'_,,_.,..........;...;...._....::;..;_.___+--6::.-'0,,,,S5:-::7;.......--,..,r1"'17 ASSIST IN RATE CASE PREPAAATION & Rl'I RESPONSES 6,810 122 ASSIST IN RATE CASE PREPAAATION & RFI R!:Sf'ONSES f=~~==::-----------+--71,"'39o.;3d-·---,2~2 ASSIST IN AATE CASE !'REPARATION & RFl RESPONSES 36,549 427 ASSIST IN RATE CASE !'REPARATION & Rl'I RESPONSES ------+---:1"'0"',3""915::+----5""19 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES ;;,;;_-------l--...:9:,;,2;x6~8---;.;i ASSIST IN RATE CASE PREPARATION & RF! RESPONSES 794 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES '--------!f---,-::-:::-::1-- ASSIST IN RATE CASE PREPARATION & Rl'I RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN AATE CASE PREPARATION & RFI RESPONSES ir:".'::::r?Ei;p;------------1-----;;-;;m----:o.J ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ---,,,,; ASSIST IN RATE CASE PREPARATION & RF! RESPONSES ASSIST IN RATE CASE PREPARATION & Ri'l RESPONSES :::------+---~:I--_-_-_-_ ...__-i;l-::i ASSIST IN AATE CASE PREPARATION & RFI RESPONSES 8 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ;;;._----+---=+---....;;i8 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 14 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES -----·r---....,,.,,'::-::;,;t---~.,.,e""°'s ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 184 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES --......,.41.,.i ASSIST IN RATE CASE PREPARATION & Rl'I RESPONSES 129 ASSIST IN RATE CASE PREPAAA110N & RFI RESPONSES :::-r-'-------1f---:=':=I--------..,,-"'1·9°'" ASSIST IN RATE CASE PREPARATION & RF! RESPONSES 167,308 fii.22 ASSIST IN RATE CASE PREPARATION & RA RESPONSES 1,&5& 49 ASSIST IN RATE CASE PREPARATION&RFI RESPONSES ----asli 7 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ::::======:::1:::::::::=1~3~,2:.-'sgcl----_-_-_-...;.10d7 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 3,016 29 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES -----+-.--;.1!;,,0.;,,90;.i_ _ _...;1;.;.i2 ASSIST IN RATE CASE !'REPARATION & FIFI RESPONSES 742 15 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES -(11,584) (133) ASSIST IN RATE CASE PREPARATION & RFl RESPONSES -----+----'.........,..43,,;7;i----'-~4 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES --·---f--_,1,2::.c.2::-:5:-:::6;......._ _1.,,,o.:lo ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 46,512 4!17 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES 1----4.,-,2"'7""71----~4~44 ASSIST IN RATE CASE PREPARATION & RF! RESPONSES 6,820 $1 ASSIST IN RATE CASE PREPARATION & RFI RESPONSES ------+--""2"'s"".s""asi:i----...39"--<9 ASSIST IN RATE CASI:. PR!:.PARATiON & RFI RESPONSES TOTAL !:.SI WAGES 2,102,309 32,592 Roadmap to internal Rate Case Expenses - Tab 1 T'i!>E oVe~r' Reikl5 1477004_21 M 2011 11 124398 GUIDANT GROUP INC TEMPORARY SERVICES I 905.34 AP10480635 33801639 09752952 R273643-0·1-66165.!$6 M 2011 11 124398 GUIDANT GROUP INC TEMPORARY SERVICES 136.99 AP104!!0il35 331301657 0975283& R295477..0-1·66165-84 M 2011 11 124398 GUIDANT GROUP !NC TEMPORARY SERVICES 704.34 AP104!lOB35 33801671:! 09752860 R305710-0-1-6615M05 ~ M M 2011 2011 11124398 12 124398 GUIDANT GROUP INC GUIDANT GROUP INC TEMPORARY SERVICES TEMPORARY SERVICES I' 1,000.95 AP10400835 401.19 AP"l04!13223 33001680 33823011 09752002 09759311 R305768-0-1-66165-107 R359765-0-1-·65370-46 M 2011 12 124396 GUIDANT GROUP INC TEMPORARY SERVICES 568.!!9 AP104&3223 33623073 09759302 R441438--0-1-6637o-91il M 2011 12 124398 GUIDANT GROUP INC TEMPORARY SERVICES 397.32 AP10483223 33823101 09759200 R473125.0·1-SG37()-126 M 2011 12 124398 GUIDANT GROUP INC TEMPORARY SERVICES 496.85 AP10483223 33623159 09759554 R53178&.()..1-66370-174 M 2011 12 124396 GUIOANT GROUP !NC TEMPORARY SERVICES 511.71 AP10464ll47 33918299 097&4431 R72367S--0-1-07127-81 M 2011 12 1243!!8 GUIDANT GROUP INC TEMPORARY SERVICES 5!1.71 AP104B5651 33966905 09795246 RS70109-0-1-67519-55 ' M 2011 12 124398 GUIDANT GROUP INC TEMPORARY SERVICES 722.40 AP104S5651 33966907 09795256 RS70727-0-1-57519-57 ' S030251l-0-1-S7&27-5!l M 2011 12 124398 GU !DANT GROUP INC TEMPORARY SERVICES 577.92 AP10400291 33978309 09798773 M 2012 1 12439!! GUIDANT GROUP INC TEMPORARY SERVICES 408.35 APi0488804 33998055 09803506 S1$4592-0-i-66076-114 M !2012 1 1.24396 GUIDA."IT GROUP !NC TEMPORARY SERVICES ! 254.41 AP104BSS04 34031076 09810506 S23636S-0-1..S8473-96 ~m n x :;:<:" :::r iJ (!) -· ro r+ [ ~ ~ s:: "" " ~ ooO -.N' ..... (Cl -i'-()'l'""' 1J Roadmap to Internal Rate Case Exj>~nses-Tab 1 M 2012 1124398 GUIDANT GROUP INC TEMPORARY SERVICES 460.53 AP10488004 34031148 09810974 M 2012 1124398 GUIDANT GROUP INC -- TEMPORARY SERVlCES 541.!lO AP104SBB04 34069179 09819123 S.264579-0-1·68473-158 S26462S-0·1·6BB12·32 M 2012 1 124396 GUIDANT GROUP INC TEMPORARY SERVICES 303.34 AP104l!8S04 34059256 09!119075 S317960-0-1.Q8612-108 M 2012 1124398 jGUIOANT GROUP INC TEMPORARY SERVICES- I 041.13 AP10490556 34108148 09828110 S335592-0.i-6913S-45 M 2012 1 124398 GUIDANT GROUP INC TEMPORARY SERVICES 283.77 AP10490551S 34108169 09823644 5366851..0-1-59136-66 M 2012 1 124398 GUIDANT GROUP INC TEMPORARY SERVICES ·} 1,566.1!4AP10490551l 34106257 09!!211763 S3$7971--0-1-69136-1M M 12012 2 124398 .~UIOANT GROUPINC TEMPORARY SERVICES 117.42 AP10492710 34136824 09836565 S439105--0·1-59472-ll4 M 20121 2 124398 GUIDANT GROUP INC TEMPORARY SERVICES 451.65 AP10492710 34136$70 09!136600 S456634-Q..1-69472-130 M 2012 L .2 12439& GUIDANT GROUP INC TEMPORARY SERVICES 722.40 Af'10492710 34136940 091136$46 54S163().(l·1-69472-100 M 2 124398 GUIDANT GROUP INC TEMPORARY SERVICES 2,724.17 AP10492715 34136801 09836748 8425612-0-1·69472-61 201* M 12012 2 124391! GUIDANT GROUP INC TEMPORARY SERVICES 105.$2 AP10493036 34174543 09644369 fS536019-0-1-69613·98 M 2012 2 124398 !GUIDANT GROUP !NC TEMPORARY SERVICES 735.95 AP10493036 34174560 091145113 SS44282-0-1-69813·115 M 2012 2 124398 GU!OANT GROOP INC TEMPORARY SERVICES I 60.22 AP1049303li 34174564 09844!;12 S5454®-0-1-600i3-119 M 2012 j 2 124398 GUIDANT GROUP INC TEMPORARY SERVICES 2,724.17 AP10493041 34174342 09644321 S478626.0-1-69ai3-37 M 2012 2 124398 GUIDANT GROUP INC TEMPORARY SERVICES 254.41 AP10494009 34212029 09853075 5633002-0-1-70207-110 M 2012 2 124396 GUIDANT GROUP INC TEMPORARY SERVICES 722-40 AP10494009 34212074 09853383 S68946!l-o.1-70207-155 M 2012 2 1243911 GUIDANT GROUP INC TEMPORARY SERVICES 2,332.46 AP10494014 34211955 09853857 S583344-0-1-70207-36 M 2012 2 124398 !GUIDANT GROUP INC TEMPORARY SERVICES 1.442.21 AP10494795 34:249064 09862186 S685807..0.1-70545-49 - M 201:2 2 124398 !GUIDANT GROUP INC TEMPORARY SERVICES 136.99 AP10494982 34249168 09862437 S712631..0.1-70545-133 M 2012 2 12439$ GUIDANT GROUP !NC TEMPORARY SER.VICES 577.92 AP104949S2 34249170 09862436 $712930-0-1-70545-135 2012 3 1243$8 I~ GUIDANT GROUP INC TEMPORARY SERVICES 254.42 AP10497469 34261327 09670263 S79$668-0-1-70609·98 2012 3 124398 GUIDANT GROUP INC TEMPORARY SERVICES 577.92 AP10497469 34281357 09670571 S800514-0-1-roGO!M 26 M 2012 3 124396 GUIDANT GROUP INC TEMPORARY SERVICES 2,385.88 AP10497474 34281280 09870084 S738$49-0-1-7000!>-51 M 2012 3 124398 !GUIDANT GROUP INC TEMPORARY SERVICES 117.42 AP10497731 34324093 098791120 5900494-0-1-71240-104 M 2012 3 124398 GUIDANT GRO\JP INC TEMPORARY SERVICES 722.40 AP104Sn31 34324207 09879921 S964S67--0-1-71240-1 &! ,....--,. M 2012 3 124398 GUIDANT GROUP INC TEMPORARY SER.VICES 1,210.74 AP1049n3e 34323993 09879787 SB63729-0-1-71240-44 ~ M 2012 2012 3 124398 3 1243$8 GUIDANT GROUP INC TEMPORARY SERVICES 749.50 AP10498940 34367915 00691280 8965117-0.1-71624-52 M GUIDANT GROUP INC !TEMPORARY SERVICES 136.99 AP10496940 34367933 09891156 5973171--0·1·11624·70 M 2012 3 124398 !GUIDANT GROUP INC TEMPORARY SERVICES I 1,335.38 AP10496943 34367907 O!iB90964 S941602-0-i-71624-44 M 2012 ! 3 124398 GUIDANT GROUP INC TEMPORARY SERVICES 185 92 AP10499811 34403196 09$98482 T084663-0-1-71!102-118 M 2012 3124398 GUIDANT GROUP INC iTEMPORARY SERVICES 541.l!O AP1049961i 34403236 098911441 T0916504-1-71902-136 M 2012 3124398 GUIDANT GROUP INC TEMPORARY SERVICES 1,638.06 APi0-499814 34403119 09898653 T050743..Q..1-71902·59 M 2012 3 12439& GUIDANT GROUP INC TEMPORARY SERVICES 39. i4 AP10500962 34441064 09909306 T174551-0-1 ·72251·1i0 M 2012 3 1243911 GUIDANT GROUP !NC TEMPORARY SERVICES 577.92 AP10500002 34441112 09909276 T210366-0-i-72251-158 M 2012 3 124398 GUIDANT GROUP INC TEMPORARY SERVICES 668.70 AP10500006 34440946 09909396 719367-1-72251-32 M 2012 3 i.24398 GUIDANT GROUP INC TEMPORARY SERVICES 417.43 AP10500966 34440947 09909403 719367-1-72251-33 M 2012 3 124398 GUIDANT GROUP INC TEMPORARY SERVICES 2.846.60 Af'10500SGO 34440987 09909317 T124402-0-1-72251-53 M 2012 4 124398 GUIDANT GROUP !NC TEMPORARY SERVICES 29.35 AP10502995 34481744 09918922 T257743-0·1-72608-69 0 om () x ;<;" ::s- -0 (() -· ro .... g: . O'l ..!.. Roadmap to Intern~! Rate. ~ase Expenses - Tab 1 .. M 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERVICES 686.28 AP10502995 34481!l50 09918941 T266245·0-1-72SOB-135 M 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERVICES 979.28 AP10503000 34481719 09910024 1"224020-0·1-72008-44 M 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERVICES 29.:.lS AP1050367B 34518260 09926918 T.168655.0-1·73004-56 M 2012 4 12439$ GUIDANT GROUP INC TEMPORARY SERVICES - 577.92 AP1050367!1 34518204 09927111 T379437-0· 1-73004-!IO M ,______ 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERVICES 2,403.68 AP10503684 34516243 09926951 T332620.0·1-73004-39 M 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERVICES 595.98 AP10504402 34558457 09935027 1"472727-0-1-73356-120 M 2012 4 124398 GUIDANT GROUP INC TEMPORARY SERV!CES 1,051.72 AP1050442m-0-1-7S47H3 V017386-0-1-7$il42-44 V15190B-0-1-7921S.56 -- l M 2012 I'! 124398 GUIDANT GROUP INC TEMPORARY SERVICES -0.63 AP10524435 35124526 10092192 U26236i-0-i-7BS43-3 M 2012 !l 124398 GUIDANT GROUP INC TEMPORARY SERVICES -0.63 AP10524435 35124717 10091788 U670743-0-1-71l843-S4 M 2012 a 124398 GUIDANT GROUP INC TEMPORARY SERVICES -0.82 AP10524435 35124742 10091297 U781454-0-i-76!143-109 M 2012 8 1243911 GUIDANT GROUP INC TEMPORARY SERVICES -0.03 AP10524435 35124756 10091259 Ull86271l-0-1-7Sll43-123 M 2012 8 124398 GUIDANT GROUP INC TEMPORARY SERVICES 426.90 AP10524710 35235243 10098441 V37096141-00015-47 1,336,1'!7.88 TOTAL TYPENOT=M 626,757.00 TOTAlFROMTYPE=MTAS 1,962,874.88 TOTAL COMPANY DIRECT EXPENSES ====~(5::6:.;;0.,..Q;.;;0"-) LESS: NON-CONFORMING COMPANY EXPENSES (Sae Add 2 to Staff 9-13 for breakout} 1,962,314.88 TOTAL REQUESiED COMPANY DIRECT EXPENSES om 87l'r' x::; ro .,._.. c.: iJ (!) :::+ ~ ~ • "O s: (j) .I'- (') 0....., 0 N ' :;ti ..... (.0 ' .!'>. U'1 ..... Roadmap to Internal Rate Case fxpen~es - Tab 2 li:IO'f;iil ;~~~~¥1W'~lfNatQe~~~i~f~~~~~rt,f~t~ lli\aWi~lNilJll$!J7 \P~ri'Wlll\Gii 1~;nime 2395 HESERT,NEAUE D 33342005 09635193 06251142987 9 024 Bw;looss Meals!Emartarnment 24.09 EEX,_SUMMAAY APi0469IO'I 0010567 TAYLOOJR,JOHN E 33392500 09646$71 09061i13398 91024 }Business Maa!slEnt<>rtainmem ' 69.4SJEEX SUMMARY lAPi0469339 !9013559 BARRILLEAUX.CHRIS E 33410594 09653768 091211135036 ' CALOWEU.,BRlAN W 33417570 09655771 091211145322 TAYl.OR JR.JOHN E 33554557 0$600104 10001i36244 OOSS,GENEE 336261111 09700411 101711126842 Business; Mea!s/Enlerta!nmenl 40.00 EEX_SUMMARY AF'\0476103 e01m::i CAWGERO,WENDY D 33657723 00713637 1025114000 lauslness Meals!Entertalnmoot 15.21 EID\_SUMMARY A?10478515 9012226 HERRINGTON.CHESTER 33712733 0072&295 i 10311219996 jBus!ness Meals/Enterlalnmenl 1,132.54 EEX_SUMMARY A?i04ll3434 9010509 FLOOO,JOHN C 33883061 oon3438 1201311627547 Business Mea!slEnlertalnment 27.66 EEX_SUMMARY AP10003678 9030496 THIRY,MICHELL.E H 34533003 00928559 04! 112190093 Business Mea!s!Entertalnmem 40.77 EEX_SUMMARY AP10504955 9010724 MORGAN,Wn.t.rAM R 345!'!6077 09'941357 04191268906 4 024 Business Mea!s/Entertalnmenl 207.13 EEX_SUMMAAY AP1050li194 9012152 OOMINO,JOSEPH F 34593266 00943519 041912415876 4 024 E!Yslness Meals/Entertalnment 50.14 EEX,_SUMMARY API0005873 9041283 OONS!OlNE.MICHAEl P 34008934 00948155 042612100869 5 024 Business Meals/Entertalnmenl 38.16 EEX SUMMARY AP10507633 0010645 COOPER.ROBERT R 34628123 09952004 ()4301200002 5 024 Business Meals/Eoteminment 4$.96 EEX_SUMl.~ -· AP10507633 9012356 GARRISON, WINFRED W 3'«l6109S 09960070 050412325491 5 024 6usioos" Mea!s/En!erlalnment 123.39 EEX_SUMMARY Af'10507633 9025842 TUMMINEU.0,STEPHANIE 6 34528188 00952733 !l43012139144 5 024 Business Meals/Entertainment l 22.46 EEX._SUMMARY A.?10507533 9031046 CHIGH!ZOl..A.MAAIA F 34628237 09952737 0501121i8001 5 024 jBusloeSs Meals/Emertainmenl I 42.91 eex_SUMMARY AP10507633 9032452 LEBl.MlC,HEATHER G $4637593 09954418 043012106541 5 024 !Business Meals/Entertaiomenl 118.46 EEJCSUMMARY AP10507633 903299$ MCCIJt.LA,MARK F 34637507 09954423 050112499386 5 IJ24 Business MealsJEmer!ainmenl 21.58 EEX_SUMMARY API050013B 9010845 COOPER.ROBERT R 34682301 099639&6 05081243399 --· 5 024 Busln8$$ Mea!s/Entertalnmeol I 47.49 EEX_SUMMARY API0500139 9011616 CICIO,PATRICK J 34682213 Q'.il964003 5 024 Business Mee!s/Errteruolnment 215.01 EEX_SUMMARY AP1050813S 0014365 TAU} Depreciation & Amort Expe~$ •••--- (Blank Value} Oepreclat10o & Amor! Expensas (Blank Value) O..precla1lon & Amort ~ses 0eprecla1ion & Amoit Expenses Depreciation & Amort Expenses Deprecialion & Amor! Expenses Depreciation & Amort Expenses IDE!)recialion & Amon Expenses O@preciatloo & Amert Expenses Depractatioo & Amort Expenses w .....-. Employee Ml9S/Funclioos1Aw111rds Employee Mt9s/functions/Awards Employae Mtgs/functlooSIAwards 33242475 33313747 33385695 33438423 33547707 09629333 1327558_21 F5PPETX011 !2011 335<16852 F5PPETX011 !2011 33780590 F5PPETIC011 !~m 33703862 F5PPETX011 l201! 2.72!EEX_SUMMARY 33703862 09747976 F5PPETX011 l2011 M!9slFunctloos/Awards 1S4.95IEEX_SUMMARY 3384195! 09795010 RiPPETX011 12011 M!gs/Func!iC. °'..:.. Roadmap to internal Rate Case Expenses - Tab 2 F5PPETX011 2012 4 IJZl !Employee MlQslFunciionsJAwards ITHIRY,MICHELLE H 34533003 F5PF'ETI«l11 2012 5 IJZT lEinployea Mt9sll'mciiorn;/Awards CITIBANK USA NA PCARD F5PPETXOi 1 2012 6 r:/1.7 IEmPIOyee Ml9s/FunctionslAwards 134899356 F5PPETX011 2012 7 WY !Employee MlQs/Functloos/Awards 35038263 F5PPETX011 2011 7 032 !Lodging 33110900 F5PPETI<011 201 t 9 032 jt.:>d9in9 33364230 F5PPE1'X011 2011 9 032 jLod9i119 33417570 F5PPE1'X011 2011 10 032 }l~9io9 33626811 F5PPETIC011 2011 11 032 ll<>dgin9 33712733 I F5PPETX011 2011 12 032 11..odQing 33893001 F5PPETX011 2012 3 002 ILod9in9 34317303 F5PPETX011 2012 F5PPETXll11 2012 032 32 4 032 4 032 4 032 5 032 5 032 9012358 5 032 ~ 5 032 9031046 5 002 !!032452 LEatANC,HEATHER G 34637593 09954418 I04301 zi!l6541 F5PPETX011 2012 9032996 MCCUll..A,MARK F 34637507 09954423 10501 !2499386 F5PPETX011 2012 9010845 COOPER.ROBERT R 34682301 00963986 105081243399 F5PPETX011 2012 10011616 CICIO,PATRICKJ !34682213 0!!964003 P-712298369 \\. \ F5PPE'TX011 2012 050012301566 105091200425 r \ ': 1F5PPETXOi1 2012 34682124 100963985 10507121711 2244806 om 0 x ~ :;; -0 (j) & m ~;:::;: co z $: m 9 "\'.J . (') 0 0' - N :::0 .t:- «> ->. ' c;n .... Roadmap to Internal Rate Case Expenses - Tab 2 0012152 iDOMINO,JOSEPH F 051712196800 'ROOERTS,RORY Ll.ITHER 052312172184 000712114113 0524121013113 0608121131171 062212100989 0714118850 08091153600 9 028 10 028 lather Employ"" l':xpepen..es Other EmploY&!I E>penses I 49.00,EEX_SU~MARY 3U6EEX_SUMMARY r-·- --:..:.;;;-.i---•rn i----·--·--- ---- ·····-· ··- ·····-------· 12 028 Olffilr Emp!oyee Expenses 12.00IEEX.....SUMMAA.Y 12 ()2$ Other Employee E>pen""" 541.23!EEX_SUMMARY 120011627547 1 028 fOlller Employee Expenses S3.34IEEX_SUMMARY 1226116334 3 028 jO!Mr Emp~ee ElSeG 26.00IEEX_SUMMAAY 03021299207 3 028 other Employee Expenses :03081280408 F5PPETX011.l2012 ! 3 028 other Employae Exl)eno;es 34382946 030412114053 F5PPETX011 /2012 3 028 Oilier Employee E>penses 34444162 F5PPE1'X011 2012 4 028 Oltier Employee E>pense& 34533003 F5PPETX011 2012 4 026 Other Emplcyoe Elpanses 4().00 EEX_SUMMARY 346Si096 !F5PPETX011 2012 --sioo EEX_SUMMARY 34628188 26.00!EEX.JMAMAAY 152.15IEEX....SUMMAAY Employee Expenses 101.51 lEEX_SUMMAAY 147.50!EEX_SUMMARY _SUMMARY Olhar Employee Exp<1mi;es .SUMMARY Olller Employee E>penses _SUMMARY Other Employee E>pensei; 050112241:\111 Other Employee expenses 05071230436$ a1m (") x IJ ;>IC :::T ru m -· oc::i -!:[ (I) z- .... 0 :s:: o~ IJ 0 0 0 ..,,N' .... ol!:i~5u~~~v S3.25!EEl\JlUMMARY 172.0S!EEX_SUMMAAY I 34637593 34682301 09954418 09963988 SS 34682213 09964003 34$82124 099539115 34682144 099639112 05\M 12244206 34715191 109971260 051412421310 34716224 09971159 05111211559 -Local 34758359 09961193 05181244253 -Local APW512621 19012152 !DOMINO.JOSEPH F 134003485 00992751 051712196609 0 om 0 x -0 ro ro "" :::; -· IQ ..... Q: ro z ...... ..... 0 :5: ..... :i,. -0 ooO ""'N' __,. © ::0 .;>. (Ji .:.. Roadmap to Internal Rate Case Expenses - Tab 2 49.00 EEX_SUMMAAV 8.33 EEX_SUMMARY AP10512621 OBERTS,RORYllJTHER RG 134816362 34843594 1-··------- 1----·- !lfi?31l1172184 000712114113 130.S!!!EEX_SUMMARY !AP105121S28 347884(}11 052412101383 27.75!EEX_SUMMARY !AP10013304 34855943 OOQ812S3871 0816129546 1396371_2!} and Overnight Delivery cmBANK USA NA 1396371_20 Postaga and O\lemigh! Deli11ary 'cmBANK USA NA 1409712_21 iPo:slage and Ovemignt Oeffvery CITIBANK USA NA 1422474_21 Postag<1 an. 01 .!.. Roadmap to Internal Rate Case Experu.>es - Tab 2 s 740 1servj;;., Company Recipient 26,628.05 SCR_SUMMAAY ALOOS11301 {Blank Value) 6 740 Se!Vlce Campany Recipient 6,534.SS SCfUlUMMARY Al-00516356 (Blank Value) 7140 Sel\llee Campany Recipient £,153.14 SCR_SUMMARY Al00521270 (Blank Value) 8140 SQIV!ce Company Recipient 3,652.41 SCR_Sl.IMMARY AL005.26273 (Blllnl?m0112012r- 3 031 Travel Transportalion 686.62 E8USUMMARY l\P10497469 0043693 BOURG.JONATHAN 34317303 00876934 F5PPETX011 2012 I 3 031 iTravel Transportation 540 36 EEX_SUMMAR'I' AP10498996 0015259 VONGl504955 9010724 MORGAN,WILUAM R 34566077 09941357 F5PPEiJW11 2012 4 031 Travel Trall$porta!lon 575.70 EEX_SUMMARY AP1o505194 !0012152 OOMlNO.JOSEPH F 34593266 09943519 F5PPETX011 2012 4 031 Travel Transportation 581.70jEEX_SUMMARY !AP10505873 0041283 CONS!OINE,MICHAEL P 34608934 09948155 F5PPETX011 2012 5 031 Travel Transportation 596.20 EEX_SUMMAAY AP10507633 0025842 TIJMMINELLO,STEPHAHJE B 34628188 09252733 lM3012139144 F5PPETX011 2012 5 031 Travel Transpc'1ation 1;12.2tl EEX SUMMARY AP10007633 0031046 CHIGH!ZO!.A,MAAIA F 34628237 09952737 060112118001 F5PPETX011 2012 s o3! !Travel Transporta!icn 594.70 EEX_SUMMAFIY AP10507633 9032452 LEBLANC.HEATHER G 34637593 0995441& 043012106541 5 031 Trav&I Transportation 1,492.45 EEX_SUMMARY AP!0007633 90:12996 MCCULlA.MAAK F 34637507 !099544:23 050112499386 s 031 TravQI Transporlalion 1,117.27 EEX_SUMMARY AP10500139 9011616 CICIO,PATRICK J 34682213 00964003 05071:2298369 5 031 Travel Transportallan 1.900.So EEX_SUMIMRY AP10500139 9014365 TALK!NGTON,MYRA L 34682262 09963$93 050812301556 N F5PPETX011 l2012 FSPPE1'X011 2012 5 5 031 031 Travel Transportation Travel Tran sportalion - 563.2ll!EEX_SUMMARY AP10508139 787.®jEEX_SUMMARY AP10506783 9041283 9034705 CONSIDINE,MICHA.a P LBVlS,JAYA 34662336 34706799 09964120 00009282 050$1296425 050112248111 \;: F5PPETX011 2012 F5PPETX011 \2012 5 5 031 031 Travel Transparla!ion Travel Transportation - 1,267.00 EEX_SUMl\llARY AP1Cl5tll!903 1,218.90 EEX....SUMMARY AP1o500041 9013658 9013646 BAARILLEAUX.CHF\IS E MAY JR,PHILUP R 34716180 w2s1:i; 00$71157 0007$231 050712304389 051512268005 5 031 TraV&I Transportalfon 726.94 EEX_SIJMMARY AP10509298 9010060 WESTERBIJRG JR.LOUIS R 34735439 09975315 050912224922 Travel Transportallcn 638.70 EEX_SUMMARY AP10510290 9035153 MCCLOSKEY.IJ.ARGARET 34777185 00985837 052412115121 !Travel Transportation :ro.oo EEX_SUMMARY APB0000002 (Blank Value} --- Tr"'"'! Transportation 21979 EEi(_SUMMAAY AP10512621 9012139 GALBRAf!H,PATRICIA 134843577 100013ll7 00071212238Q Travel TransportaUon 479.20 EEX_SUMMAAY A.Pl 0512621 $012152 DOMINO,JOSEPii F (34603465 00992761 051712196809 Travel Transportation 1,059.SS EEJ(_SUMMAAY AP 1051:2621 9013£98 ROBERTS.RORY LIJTHER 34816362 00995198 05:2312172184 F5PPETX011 12012 I 61031 !Travel Transportatioo 20.00 EEX._SUMMAAY AP10512621 9019330 DOUCET.DONNA (34788179 09986725 05291266932 ..... 0 a' m x !»"~ (!) :::r -· u::i ...... cr ro z;:;: ...... 0 :!!!: (..) :i,.. "O 000 - «I ..... rv Al • .i:. 01 .!... Roadmap to Internal Rate Case Expenses - Tab 2 F5PPETI -· IC ro 2: z- ..... __,, 0 :5: ~~ -0 0 0 (') - I\) • _.. ID :Al .j>. 01 ~ ·1·· · · · · · · · SOAH DOCKET NO. XXX-XX-XXXX · · ·2·· · · · · · · · · · PUC DOCKET NO. 40295 · · ·3·· · · ·4··APPLICATION OF ENTERGY· · ·§··BEFORE THE STATE OFFICE · · · · · · · · · · · · · · ·· § ·5··TEXAS, INC. FOR RATE CASE··§ · · · · · · · · · · · · · · ·· §· · · · · ··OF ·6··EXPENSES PERTAINING TO· · ·§ · · · · · · · · · · · · · · ·· § ·7··PUC DOCKET NO. 39896· · · ·§··ADMINISTRATIVE HEARINGS · · ·8·· · · ·9·· · · · · · · · ·· HEARING ON THE MERITS · · 10·· · · · · · · · WEDNESDAY, NOVEMBER 28, 2012 · · 11·· · · 12·· · · · ·· BE IT REMEMBERED THAT at 10:00 a.m., on · · 13··Wednesday, the 28th day of November 2012, the · · 14··above-entitled matter came on for hearing at the State · · 15··Office of Administrative Hearings, 300 West 15th Street, · · 16··Room 408A, Austin, Texas, before HUNTER BURKHALTER, · · 17··Administrative Law Judge, and the following proceedings · · 18··were reported by Steven Stogel, a Certified Shorthand · · 19··Reporter. · · 20·· · · 21·· · · 22·· · · 23·· · · 24·· · · 25·· Page 2 ·1·· · · · · · · · ··A P P E A R A N C E S · · ·2·· ·FOR ENTERGY TEXAS, INC.: · · ·3·· · · · ··Mr. Steven Neinast ·4·· · ··Assistant General Counsel · · · · · · ·- and - ·5·· · ··Ms. Wajiha S. Rizvi · · · ··Counsel ·6·· · ··ENTERGY SERVICES, INC. · · · ··919 Congress Avenue, Suite 840 ·7·· · ··Austin, Texas 78701 · · · ··Telephone:··512.487.3957 - Fax:··512.487.3958 ·8·· · ··Email: wrizv90@entergy.com · · · · · · ·- and - ·9·· · ··Mr. George Hoyt · · · ··DUGGINS WREN MANN & ROMERO, LLP 10·· · ··600 Congress Avenue, Suite 1900 · · · ··Austin, Texas··78701 11·· · ··Telephone:··512.744.9300 - Fax: 512.744.9399 · · · ··Email: ghoyt@dwmrlaw.com 12·· · · 13··FOR THE OFFICE OF THE PUBLIC UTILITY COUNSEL: · · 14·· · ··Ms. Sara J. Ferris · · · ··Assistant Public Counsel 15·· · ··OFFICE OF PUBLIC UTILITY COUNSEL · · · ··1701 N. Congress Avenue, Suite 9-180 16·· · ··Austin, Texas 78701 · · · ··Telephone:··512.936.7500 17·· · ··Email: opuc_eservice@opc.state.tx.us · · 18·· ·FOR THE PUBLIC INTEREST: · · 19·· · · · ··Mr. Brennan J. Foley 20·· · ··Attorney-Legal Division · · · ··PUBLIC UTILITY COMMISSION OF TEXAS 21·· · ··1701 N. Congress Avenue, Suite 8-110 · · · ··Austin, Texas 78701 22·· · ··Telephone:··512.936.7163 - Fax:··512.936.7268 · · 23·· · · 24·· · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 3 ·1·· · · · · · · · ··A P P E A R A N C E S · · ·2·· · · ·3··FOR THE CITIES: · · ·4·· · ··Mr. Stephen Mack · · · ··LAWTON LAW FIRM ·5·· · ··701 Brazos, Suite 500 · · · ··Austin, Texas 78701 ·6·· · ··Telephone:··512.322.0019 - Fax:··512.716.8917 · · ·7·· ·FOR STATE AGENCIES: · · ·8·· · · · ··Ms. Susan M. Kelley ·9·· · ··Assistant Attorney General · · · ··OFFICE OF THE ATTORNEY GENERAL 10·· · ··P.O. Box 12548 · · · ··Austin, Texas 78711-2548 11·· · ··Telephone:··512.475.4173 - Fax:··512.320.0167 · · · ··Email: susan.kelley@texasattorneygeneral.gov 12·· · · 13··FOR TEXAS INDUSTRIAL ENERGY CONSUMERS: · · 14·· · ··Ms. Meghan E. Griffiths · · · ··ANDREWS KURTH, LLP 15·· · ··111 Congress Avenue, Suite 1700 · · · ··Austin, Texas 78701 16·· · ··Telephone:··512.320.9214 - Fax:··512.320.9292 · · · ··email: meghangriffiths@andrewskurth.com 17·· · · 18·· · · 19·· · · 20·· · · 21·· · · 22·· · · 23·· · · 24·· · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 4 ·1·· · · · · · · · · ··TABLE OF CONTENTS · · ·2·· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE · · ·3··PROCEEDINGS, WEDNESDAY, NOVEMBER 28, 2012· · · · · ··11 · · ·4··OPENING STATEMENT ON BEHALF OF ·APPLICANT ENTERGY TEXAS, INC.· · · · · · · · · · · ··17 · · ·5·· ·OPENING STATEMENT ON BEHALF OF CITIES· · · · · · · ··22 · · ·6·· ·OPENING STATEMENT ON BEHALF OF · · ·7··OFFICE OF PUBLIC UTILITY COUNSEL· · · · · · · · · · ·22 · · ·8··OPENING STATEMENT ON BEHALF OF STATE AGENCIES· · · ··23 · · ·9··OPENING STATEMENT ON BEHALF OF ·TEXAS INDUSTRIAL ENERGY CONSUMERS· · · · · · · · · ··28 · · 10·· ·PRESENTATION ON BEHALF OF · · 11··APPLICANT ENTERGY TEXAS, INC.· · · · · · · · · · · ··30 · · 12·· · ··MICHAEL P. CONSIDINE · · · · · · ·- Direct (Rizvi)· · · · · · · · · · · · · ·30 13·· · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·32 · · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·43 14·· · · · · ·- Redirect (Rizvi)· · · · · · · · · · · · ·46 · · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·48 15·· · · · ··STEPHEN F. MORRIS 16·· · · · · ·- Direct (Hoyt)· · · · · · · · · · · · · ··51 · · · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·54 17·· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·75 · · · · · · ·- Redirect (Hoyt)· · · · · · · · · · · · ··80 18·· ·PRESENTATION ON BEHALF OF · · 19··OFFICE OF PUBLIC UTILITY COUNSEL· · · · · · · · · · ·83 · · 20·· · ··NATHAN BENEDICT · · · · · · ·- Direct (Ferris)· · · · · · · · · · · · ··83 21·· · · · · ·- Cross (Foley)· · · · · · · · · · · · · ··85 · · · · · · ·- Clarifying (Burkhalter)· · · · · · · · ··86 22·· · · · · ·- Redirect (Ferris)· · · · · · · · · · · ··87 · · 23··PROCEEDINGS CONCLUDED· · · · · · · · · · · · · · · ··89 · · 24··REPORTER'S CERTIFICATE· · · · · · · · · · · · · · · ·90 · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 5 ·1·· · · · · · · · · · ··EXHIBIT INDEX · · ·2··CITIES· · · · · · · · · · · · · · · · · ·MARKED ADMITTED · · ·3··1.· · · ··Direct Testimony and Exhibits · · · · · · ·of Amalija J. Hodgins filed in ·4·· · · · · ·Docket No. 39896· · · · · · · · · ·11· · · ·82 · · ·5··2.· · · ··Supplemental Direct Testimony · · · · · · ·of Amalija J. Hodgins· · · · · · ··11· · · ·82 ·6·· · · ·7·· · · ·8·· · · ·9·· · · 10·· · · 11·· · · 12·· · · 13·· · · 14·· · · 15·· · · 16·· · · 17·· · · 18·· · · 19·· · · 20·· · · 21·· · · 22·· · · 23·· · · 24·· · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 6 ·1·· · · · · · · · · · ··EXHIBIT INDEX · · ·2··COMMISSION STAFF· · · · · · · · · · · · ·MARKED ADMITTED · · ·3··1.· · · ··Direct Testimony of Brian T. · · · · · · ·Murphy· · · · · · · · · · · · · · ·11· · · ·89 ·4·· ·2.· · · ··ETI Response to State of · · ·5·· · · · · ·Texas RFI 3-17· · · · · · · · · · ·11 · · ·6·· · · ·7·· · · ·8·· · · ·9·· · · 10·· · · 11·· · · 12·· · · 13·· · · 14·· · · 15·· · · 16·· · · 17·· · · 18·· · · 19·· · · 20·· · · 21·· · · 22·· · · 23·· · · 24·· · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 7 ·1·· · · · · · · · · · ··EXHIBIT INDEX · · ·2··ENTERGY· · · · · · · · · · · · · · · · ··MARKED ADMITTED · · ·3··1.· · · ··Docket No. 39896 - Direct · · · · · · ·Testimony of Michael P. ·4·· · · · · ·Considine (Redacted filed · · · · · · ·11/28/11)· · · · · · · · · · · · ··11· · · ·31 ·5·· ·2.· · · ··Schedule G-14.1· · · · · · · · · ··11· · · ·31 · · ·6·· ·3.· · · ··Rate Case Expenses Rider and · · ·7·· · · · · ·Cost Allocations· · · · · · · · · ·11· · · ·31 · · ·8··4.· · · ··Docket No. 39896 - Supplemental · · · · · · ·Direct Testimony and Exhibits of ·9·· · · · · ·Michael P. Considine (3/13/12)· · ·11· · · ·31 · · 10··5.· · · ··Docket No. 40295 - Supplemental · · · · · · ·Direct Testimony and Exhibits of 11·· · · · · ·Michael P. Considine (10/5/12)· · ·11· · · ·31 · · 12··6.· · · ··Docket No. 40295 - Supplemental · · · · · · ·Direct Testimony and Exhibits of 13·· · · · · ·Michael P. Considine (10/25/12)· ··11· · · ·31 · · 14··7.· · · ··Docket No. 40295 - Rebuttal · · · · · · ·Testimony and Exhibits of 15·· · · · · ·Michael P. Considine (11/15/12)· ··11· · · ·31 · · 16··8.· · · ··Docket No. 39896 - Direct · · · · · · ·Testimony and Exhibits of 17·· · · · · ·Stephen F. Morris (11/28/11)· · · ·11· · · ·53 · · 18··9.· · · ··Docket No. 39896 - Supplemental · · · · · · ·Direct Testimony of Stephen F. 19·· · · · · ·Morris (3/13/12)· · · · · · · · · ·11· · · ·53 · · 20··10.· · · ·Docket No. 40295 - Supplemental · · · · · · ·Direct Testimony of Stephen F. 21·· · · · · ·Morris (10/5/12)· · · · · · · · · ·11· · · ·53 · · 22··11.· · · ·Docket No. 40295 - Supplemental · · · · · · ·Direct Testimony of Stephen F. 23·· · · · · ·Morris (10/25/12)· · · · · · · · ··11· · · ·53 · · 24··12.· · · ·Docket No. 40295 - Rebuttal · · · · · · ·Testimony of Stephen F. 25·· · · · · ·Morris (11/15/12)· · · · · · · · ··11· · · ·53 KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 8 ·1·· · · · · · · · · · ··EXHIBIT INDEX · · ·2··OPUC· · · · · · · · · · · · · · · · · · ·MARKED ADMITTED · · ·3··1.· · · ··Direct Testimony and Workpapers · · · · · · ·of Nathan A. Benedict· · · · · · ··11· · · ·84 ·4·· ·2.· · · ··ETI Response to OPUC RFI 3-1, · · ·5·· · · · · ·3-2 and 3-3· · · · · · · · · · · ··43· · · ·46 · · ·6··3.· · · ··2/3/11 PUC Open Meeting · · · · · · ·Excerpt· · · · · · · · · · · · · ··75· · · ·75 ·7·· · · ·8·· · · ·9·· · · 10·· · · 11·· · · 12·· · · 13·· · · 14·· · · 15·· · · 16·· · · 17·· · · 18·· · · 19·· · · 20·· · · 21·· · · 22·· · · 23·· · · 24·· · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 9 ·1·· · · · · · · · · · ··EXHIBIT INDEX · · ·2··STATE AGENCIES· · · · · · · · · · · · · ·MARKED ADMITTED · · ·3··1.· · · ··Response to Staff's RFI 9-1, · · · · · · ·Including Add. 1, Add. 2 and ·4·· · · · · ·Add. 3 (on CD)· · · · · · · · · · ·11· · · ·16 · · ·5··2.· · · ··Invoices from Naman Howell · · · · · · ·(Included in SA #1)· · · · · · · ··54· · · ·61 ·6·· ·3.· · · ··ETI Response to State · · ·7·· · · · · ·Agencies' RFI 3-17· · · · · · · · ·11· · · ·16 · · ·8··4.· · · ··ETI Response to State · · · · · · ·Agencies' RFI 1-2· · · · · · · · ··34· · · ·35 ·9·· ·5.· · · ··ETI Response to Staff RFI 9-9· · ··38· · · ·39 · · 10·· ·6.· · · ··ETI Response to State · · 11·· · · · · ·Agencies' RFI 10-1· · · · · · · · ·54· · · ·58 · · 12··7.· · · ··ETI Response to State · · · · · · ·Agencies' RFI 10-2· · · · · · · · ·54· · · ·58 13·· ·8.· · · ··ETI Response to State · · 14·· · · · · ·Agencies' RFI 10-11· · · · · · · ··54· · · ·62 · · 15··9.· · · ··ETI Response to State · · · · · · ·Agencies' RFI 9-13· · · · · · · · ·36· · · ·37 16·· ·10.· · · ·OPEN · · 17·· ·11.· · · ·ETI Response to State · · 18·· · · · · ·Agencies' RFI 9-8· · · · · · · · ··38· · · ·41 · · 19··12.· · · ·ETI Response to Staff RFI 1-8· · ··38· · · ·40 · · 20··13.· · · ·ETI Response to State · · · · · · ·Agencies' RFI 10-6· · · · · · · · ·11· · · ·16 21·· ·14.· · · ·Texas Lawyer Hourly Billing · · 22·· · · · · ·Rates Survey 2011· · · · · · · · ··54· · · ·63 · · 23··15.· · · ·Duggins, Wren Contract with · · · · · · ·Naman Howell· · · · · · · · · · · ·54· · · ·55 24·· · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 10 ·1·· · · · · · · · · · ··EXHIBIT INDEX · · ·2··STATE AGENCIES· · · · · · · · · · · · · ·MARKED ADMITTED · · ·3··16.· · · ·ETI Response to State · · · · · · ·Agencies' RFI 2-3· · · · · · · · ··11· · · ·16 ·4·· ·17.· · · ·Excerpt of 12/8/11 Duggins, · · ·5·· · · · · ·Wren Law Firm Bill (Entire · · · · · · ·Bill Included in Exhibit 1)· · · ··54· · · ·71 ·6·· · · ·7·· · · ·8·· · · ·9·· · · 10·· · · 11·· · · 12·· · · 13·· · · 14·· · · 15·· · · 16·· · · 17·· · · 18·· · · 19·· · · 20·· · · 21·· · · 22·· · · 23·· · · 24·· · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 11 ·1·· · · · · · · · ··P R O C E E D I N G S ·2·· · · · · · · ·WEDNESDAY, NOVEMBER 28, 2012 ·3·· · · · · · · · · · · ·(10:00 a.m.) ·4·· · · · · · · ·(Exhibit Cities Nos. 1 and 2 marked) ·5·· · · · · · · ·(Exhibit Commission Staff Nos. 1 and 2 ·6·· · · · · · · ·marked) ·7·· · · · · · · ·(Exhibit ETI Nos. 1 through 12 marked) ·8·· · · · · · · ·(Exhibit OPUC No. 1 marked) ·9·· · · · · · · ·(Exhibit State Agencies Nos. 1, 3, 13 and 10·· · · · · · · ·16 marked) 11·· · · · · · · ·JUDGE BURKHALTER:··I'll call to order 12··Docket No. XXX-XX-XXXX.··It's PUC Docket No. 40295. 13··It's a case styled Application of Entergy Texas, Inc., 14··for Rate Case Expenses Severed from PUC Docket 15··No. 39896. 16·· · · · · · · ·This is Judge Burkhalter.··It's Wednesday, 17··November 28, 2012.··It's 10:00 in the morning, and we 18··are in Austin, Texas.··Let me take appearances, and I'll 19··just start with the Applicant and work our way down the 20··table, please. 21·· · · · · · · ·MR. NEINAST:··Thank you, Your Honor. 22··Steve Neinast with Entergy Texas.··I'd also like to 23··enter the appearance of Wajiha Rizvi with Entergy Texas 24··and George Hoyt with the Duggins Wren law firm. 25·· · · · · · · ·JUDGE BURKHALTER:··Welcome to you-all. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 12 ·1·· · · · · · · ·MR. MACK:··Stephen Mack for the Cities, ·2··Your Honor. ·3·· · · · · · · ·MS. FERRIS:··Good morning, Your Honor. ·4··Sarah Ferris with the Office of Public Utility Counsel. ·5·· · · · · · · ·MS. KELLEY:··Good morning, Your Honor. ·6··Sue Kelley for the State Agencies. ·7·· · · · · · · ·MS. GRIFFITHS:··Good morning.··Meghan ·8··Griffiths for Texas Industrial Energy Consumers. ·9·· · · · · · · ·MR. FOLEY:··Good morning, Your Honor. 10··Brennan Foley for Commission Staff. 11·· · · · · · · ·JUDGE BURKHALTER:··Okay.··We took care of 12··a little bit of business before we went on the record by 13··agreement.··The parties are going to admit the direct 14··testimony of Cities' witness, Amy Hodgins, and waive 15··cross on her, and likewise with Staff's witness, Brian 16··Murphy.··Correct? 17·· · · · · · · ·MR. MACK:··Your Honor, and she also had 18··supplemental direct testimony, Exhibits 1 and 2.··Her 19··direct is Exhibit 1 and supplemental is Exhibit 2. 20·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thanks.··Is 21··there any other business we can take care of before we 22··go to opening statements? 23·· · · · · · · ·MS. KELLEY:··Yes, Your Honor.··I have some 24··exhibits I put up there near you which the Company has 25··agreed can be admitted.··And I don't think anybody else KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 13 ·1··has objection to it, but I'll let them speak for ·2··themselves.··That would be -- ·3·· · · · · · · ·JUDGE BURKHALTER:··Let me first ask -- ·4·· · · · · · · ·MS. KELLEY:··Yes. ·5·· · · · · · · ·JUDGE BURKHALTER:··Has everybody given me ·6··a copy? ·7·· · · · · · · ·MS. KELLEY:··Yes. ·8·· · · · · · · ·JUDGE BURKHALTER:··And two record copies ·9··of exhibits?··I've got a bunch of paper up here, but I 10··just want to make sure.··Yes? 11·· · · · · · · ·MS. KELLEY:··Yes. 12·· · · · · · · ·JUDGE BURKHALTER:··Okay.··And, of course, 13··the court reporter as well.··Okay.··So you are State 14··Agencies -- 15·· · · · · · · ·MS. KELLEY:··And it will be State Agency 16··No. 1, which includes a CD, which you've been given.··A 17··brief explanation about the CD -- 18·· · · · · · · ·JUDGE BURKHALTER:··Wait just a second. 19··Let me get organized here. 20·· · · · · · · ·MS. KELLEY:··Okay.··Yes, sir. 21·· · · · · · · ·JUDGE BURKHALTER:··I have -- they're not 22··in order, I guess.··I've got State's Exhibit 1, 3 -- a 23··couple of State's Exhibit 3 and 16 and 13. 24·· · · · · · · ·MS. KELLEY:··Okay. 25·· · · · · · · ·JUDGE BURKHALTER:··And 13. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 14 ·1·· · · · · · · ·MS. KELLEY:··And 13, yes. ·2·· · · · · · · ·JUDGE BURKHALTER:··Is that the universe of ·3··exhibits you're wanting -- ·4·· · · · · · · ·MS. KELLEY:··That is.··If you don't mind ·5··if I recover that No. 3. ·6·· · · · · · · ·JUDGE BURKHALTER:··I don't mind. ·7·· · · · · · · ·MS. KELLEY:··Because that means that ·8··someone else has got them.··Thank you. ·9·· · · · · · · ·A brief explanation about No. 1.··It is a 10··copy of the Company's response plus three addendum 11··responses all on that same disc to Staff's RFI 9-1. 12··Whenever we copy a CD that we've been provided with, as 13··was the case here, it's encrypted.··So the decryption 14··program is also on that disc, and the password -- yes, 15··sir. 16·· · · · · · · ·JUDGE BURKHALTER:··Wait, wait.··I have a 17··piece of paper that is State's Exhibit 1. 18·· · · · · · · ·MS. KELLEY:··Yes.··They go together. 19·· · · · · · · ·JUDGE BURKHALTER:··These go together? 20·· · · · · · · ·MS. KELLEY:··Yes. 21·· · · · · · · ·JUDGE BURKHALTER:··Okay.··All right.··Go 22··ahead. 23·· · · · · · · ·MS. KELLEY:··Okay.··The decryption 24··password is right on the front with no spaces, just as 25··you see here, and then you can read it very easily. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 15 ·1·· · · · · · · ·JUDGE BURKHALTER:··Okay.··So -- well, go ·2··ahead.··You want to describe them all, and then we'll ·3··see if we have any objections. ·4·· · · · · · · ·MS. KELLEY:··Okay.··Exhibit 3 is a ·5··response to -- Company's response to State Agencies' RFI ·6··3-17, 13 is a response to State Agencies' RFI 10-6, and ·7··16 is a response to State Agencies' RFI 2-3.··We would ·8··offer those into evidence. ·9·· · · · · · · ·JUDGE BURKHALTER:··All right.··Any 10··objection to the admission of State's Exhibits 1, 3, 13, 11··and 16? 12·· · · · · · · ·MR. NEINAST:··Your Honor, if you could 13··give me just a minute.··I don't have them in front of 14··me.··If they're the same exhibits, I don't have a 15··problem.··I just need to -- 16·· · · · · · · ·JUDGE BURKHALTER:··While he's looking, let 17··me ask you, Ms. Kelley.··You've given me an exhibit list 18··with 17 exhibits listed. 19·· · · · · · · ·MS. KELLEY:··Yes. 20·· · · · · · · ·JUDGE BURKHALTER:··Are you not offering 21··the remainder, or are you going to be offering them 22··later? 23·· · · · · · · ·MS. KELLEY:··They're coming in -- 24·· · · · · · · ·JUDGE BURKHALTER:··All right. 25·· · · · · · · ·MS. KELLEY:··-- because I have some KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 16 ·1··questions about them. ·2·· · · · · · · ·JUDGE BURKHALTER:··Okay. ·3·· · · · · · · ·MR. NEINAST:··No objections, Your Honor. ·4·· · · · · · · ·JUDGE BURKHALTER:··All right.··They're ·5··admitted. ·6·· · · · · · · ·(Exhibit State Agencies Nos. 1, 3, 13, and ·7·· · · · · · · ·16 admitted) ·8·· · · · · · · ·JUDGE BURKHALTER:··Does anybody else want ·9··to take care of exhibits at this point? 10·· · · · · · · ·(No response) 11·· · · · · · · ·JUDGE BURKHALTER:··All right.··Opening -- 12·· · · · · · · ·MR. NEINAST:··Before we get started -- 13·· · · · · · · ·JUDGE BURKHALTER:··Yes, sir. 14·· · · · · · · ·MR. NEINAST:··We can do this later, but 15··the record from the rate case was not technically 16··carried forward into this docket, but there are a number 17··of documents that are in the record of the rate case 18··that I think are going to be -- or referenced or 19··relevant to this one.··So we would ask that you take 20··judicial notice of the record in Docket 39896 so that we 21··can use documents from that docket in this docket. 22·· · · · · · · ·JUDGE BURKHALTER:··Anybody object to that? 23·· · · · · · · ·(No response) 24·· · · · · · · ·JUDGE BURKHALTER:··All right.··So I think 25··we're ready for opening statements.··Mr. Neinast? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 17 ·1·· · · · · · ··OPENING STATEMENT ON BEHALF OF ·2·· · · · · · ··APPLICANT ENTERGY TEXAS, INC. ·3·· · · · · · · ·MR. NEINAST:··Good morning, Your Honor. ·4··My name is Steve Neinast, and I'm counsel for Entergy ·5··Texas.··We appreciate the opportunity to make a brief ·6··opening statement. ·7·· · · · · · · ·In this case, ETI seeks authority to ·8··recover a total of approximately 8.75 million in rate ·9··case expenses incurred through September 30, 2012. 10··These costs include roughly 7.6 million incurred by the 11··Company and roughly 1.1 million incurred by the Cities. 12··The Company proposes to recover these amounts through a 13··three-year surcharge with a return on the unamortized 14··balance.··In addition, the Company seeks authority to 15··defer until the next rate case all rate case expenses 16··incurred after September 30, 2012. 17·· · · · · · · ·The Company's rate case expenses are 18··presented and supported by testimonies and exhibits of 19··Company witnesses Michael Considine and Stephen Morris, 20··and the Company responded to numerous RFIs regarding the 21··detail of those expenses in both this case and the rate 22··case in Docket No. 39896. 23·· · · · · · · ·The testimony and recommendations filed by 24··Staff and Intervenors were limited to relatively few 25··issues.··First, Staff filed testimony proposing a KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 18 ·1··slightly different allocation of the expenses.··The ·2··Company does not object to Staff's proposal.··On the ·3··other hand, Staff recommended that the Company not be ·4··permitted a return on the unamortized balance of the ·5··rate case expenses. ·6·· · · · · · · ·As explained in the Company's rebuttal ·7··testimony, rejecting the requested return component ·8··would prevent the Company from recovering the full cost ·9··of these expenses over time since it would simply do 10··away with any consideration of the time value of money. 11·· · · · · · · ·We're proposing to recover these costs 12··over three years rather than immediately in a lump sum. 13··With regard to the limited number of specific rate case 14··expenses challenged by Staff and Intervenors, the 15··Company addressed each category of cost in rebuttal 16··testimony to show that the challenged costs were 17··reasonable. 18·· · · · · · · ·Finally, State Agencies and OPC recommend 19··global and novel disallowances based on unprecedented 20··methods of determining rate case expense recovery.··In 21··particular, they seek to require that admittedly 22··reasonable and necessary costs of preparing and 23··participating in a rate case be disallowed and borne by 24··shareholders.··Based on these novel policy-based 25··disallowances, State Agencies and OPC recommend KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 19 ·1··disallowances ranging from roughly 1.3 million to 6.4 ·2··million, representing disallowances of from 14.5 percent ·3··to 73.6 percent of ETI's rate case expenses. ·4·· · · · · · · ·This range of disallowances bears no ·5··relationship to those very charges challenged as ·6··unreasonable by State Agencies and OPC and no ·7··relationship to the reasonable cost of preparing and ·8··prosecuting this case.··These claims should be rejected. ·9·· · · · · · · ·Moreover, these proposals represent a 10··radical departure from established Commission precedent. 11··For example, in the Commission's last litigated rate 12··case expense docket, which was AEP Texas Central, Docket 13··No. 31433.··The Commission allowed the utility to 14··recover all the rate case expenses found to be 15··reasonable and necessary and did not require that 16··shareholders bear any portion of those costs via any 17··sort of policy-based sharing.··Such an approach is at 18··odds -- the approach that OPC and the State Agencies 19··propose is at odds with the provisions of PURA allowing 20··the Company to recover its reasonable and necessary 21··expense incurred to prosecute rate cases. 22·· · · · · · · ·OPC and State Agencies have not shown why 23··the Commission should start using a different approach 24··in this case, an approach that has no connection to 25··whether cost incurred was a reasonable cost in the KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 20 ·1··context of the given case. ·2·· · · · · · · ·It is important to understand ETI's rate ·3··case expenses are driven by the Commission's RFP ·4··requirements and the fact that the utility has the ·5··burden of proof to justify all of its requested ·6··revenues, not just the requested rate increase, with an ·7··even heightened standard applied to the Company's ·8··affiliate expenses. ·9·· · · · · · · ·ETI has filed three rate cases in the last 10··five years, each of those cases, either through 11··settlement or litigation, resulted in a rate increase. 12··To now adopt a new rate case expense paradigm that would 13··disallow actual incurred costs shown to be reasonable is 14··simply punitive and confiscatory. 15·· · · · · · · ·It is also important to note that ETI has 16··attempted, in these past three rate cases, to implement 17··ratemaking mechanisms that would reduce the number of 18··rate cases that the Company needs to file in an attempt 19··to recover its actual cost of service.··These include 20··purchase capacity recovery factors and a formula rate 21··plan.··But the parties that here seek to disallow 22··reasonable rate case expenses vigorously oppose ETI's 23··attempts to implement purchase capacity and formula rate 24··plan mechanisms.··It is surprising that State Agencies 25··and OPC argue that ETI's rate case expenses should be KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 21 ·1··drastically disallowed even when reasonable, while on ·2··the other hand opposing the very rate case streamlining ·3··mechanism that would have mitigated those expenses. ·4·· · · · · · · ·As everyone in this room is aware, the ·5··ratemaking scheme in place today is very work intensive. ·6··For example, ETI was served with over 1,900 RFI ·7··questions, including subparts, in the base rate case. ·8··We needed 19 witnesses with subject matter expertise to ·9··present our affiliate case.··If a utility is 10··under-recovering its costs, it has no choice but to file 11··another base rate case.··And given ETI's recent history 12··with the three rate cases, it really can't be disputed 13··that our revenue requirements have been scrutinized and 14··scrutinized again to ensure that we are not 15··over-recovering.··In fact, given the purchase capacity 16··disallowances in the last rate case, we were already 17··under-recovering our costs on the first day of the rate 18··year. 19·· · · · · · · ·In summary, the policy disallowances 20··approach advocated by State Agencies and OPC is novel, 21··contrary to longstanding Commission precedent, punitive 22··and confiscatory.··The better approach to addressing 23··State Agencies' and OPC's concerns would be to 24··streamline the ratemaking paradigm currently in place. 25··Accordingly, the Company respectfully requests that it KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 22 ·1··be authorized to recover its requested rate case ·2··expenses through a three-year surcharge, with a return ·3··on the unamortized balance.··Thank you. ·4·· · · · · · · ·JUDGE BURKHALTER:··Thank you.··Mr. Mack? ·5·· · · · ··OPENING STATEMENT ON BEHALF OF CITIES ·6·· · · · · · · ·MR. MACK:··Thank you, Your Honor.··Stephen ·7··Mack for Cities.··Cities in this case are requesting ·8··reimbursement from ETI of their rate case expenses ·9··pursuant to PURA Section 33.023.··Those rate case 10··expenses are set out in the direct testimony of Amy 11··Hodgins, and we're requesting a finding of 12··reasonableness and that they be reimbursed.··Thank you. 13·· · · · · · · ·JUDGE BURKHALTER:··And the amount is what? 14·· · · · · · · ·MR. MACK:··The amount is 1.2 million, 15··which is actual expenses and estimated expenses for the 16··Long Law Firm and eight consulting firms. 17·· · · · · · · ·JUDGE BURKHALTER:··Thank you.··Ms. Ferris? 18·· · · · · · ··OPENING STATEMENT ON BEHALF OF 19·· · · · · ·THE OFFICE OF PUBLIC UTILITY COUNSEL 20·· · · · · · · ·MS. FERRIS:··Thank you, Your Honor.··This 21··is a rate case expense docket, not a rulemaking 22··regarding how rates are set at the Commission. 23·· · · · · · · ·However, the one thing that OPC is really 24··asking the Commission to do in this case is to exercise 25··its discretion under PURA 36.061 to decide what KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 23 ·1··reasonable expenses should be allowed to be recovered by ·2··the Company.··Traditionally this exercise has looked at ·3··accounting entries and there's nothing wrong with that. ·4··That's appropriate.··But it's not the limit of what the ·5··Commission's discretion is. ·6·· · · · · · · ·OPC is asking the Commission to look at ·7··other considerations when they set what the reasonable ·8··rate case expenses to be recovered are.··And the ·9··testimony of Nathan Benedict outlines some of the 10··reasonable considerations that the Commission should 11··look at, and we ask them to look at.··And that may 12··include frequency of how they come in.··It could be what 13··the award was versus how much the expense was.··It could 14··be was longstanding precedent challenged.··There are 15··other things.··That's not the limit of the Commission's 16··discretion.··It's fairly broad.··And we are asking the 17··Commission to exercise their discretion in this case. 18··Thank you. 19·· · · · · · · ·JUDGE BURKHALTER:··Thank you.··Ms. Kelley? 20·· · ··OPENING STATEMENT ON BEHALF OF STATE AGENCIES 21·· · · · · · · ·MS. KELLEY:··Yes, Your Honor.··You know, 22··I've been thinking in this case as I've reviewed some of 23··the evidence that's been submitted and a lot of what's 24··on State Agencies No. 1. 25·· · · · · · · ·I've had occasion, a lot of times, KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 24 ·1··traveling to Southeast Texas to visit relatives, and ·2··I've been mindful as I review those documents about one ·3··of my favorite political commentators, Paul Burka, has ·4··said about the Texas Legislation.··They imply something ·5··called a Bubba factor to the legislation, and it's ·6··basically how would the ordinary person feel about the ·7··practical effects of what we're asking them to do. ·8·· · · · · · · ·So I've asked myself as I've reviewed ·9··these costs how would Bubba the ratepayer feel about $7 10··cab fares by law firm staffers from the PUC back to the 11··law firm that's only a few blocks away and on a main 12··baseline?··How would the ratepayer feel about frequent 13··courier service to deliver copies when email or fax 14··would suffice?··How would the ratepayer feel about ten 15··outside lawyers on a case, in addition to internal 16··staff, many of whom merely sit observing during a 17··hearing, even though that same law firm orders overnight 18··transcripts of the hearing that could be consulted when 19··needed? 20·· · · · · · · ·How would the ratepayer feel about 21··furnishing ordinary snacks for the workday, bottled 22··water and catered lunches for employees that otherwise 23··would have to pay for that themselves?··How would the 24··ratepayer feel about paying not just for the salaries of 25··company people who work on rate cases, but for so-called KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 25 ·1··loaders who try and load in indirect costs and pass ·2··along the costs of buildings and equipment, if we can ·3··load in depreciation, can mortgage payments be much ·4··farther behind? ·5·· · · · · · · ·Now, I know the argument will be made ·6··that -- and sort of has been made already by the ·7··Company -- as if the burden of proof is on the ·8··Intervenors to kind of fly through this with more ·9··limited resources than the available to the Company to 10··come up with dollar amounts.··And I know there will be 11··considerable verbiage that we have "only" -- I put air 12··quotes, Mr. Court Reporter -- identified small costs 13··against nearly $10 million.··And that's -- it's nearly 14··10 million if you include the carrying charges they 15··seek. 16·· · · · · · · ·JUDGE BURKHALTER:··Include what?··Courier 17··charges?··Or did you say -- 18·· · · · · · · ·MS. KELLEY:··Carrying charges. 19·· · · · · · · ·JUDGE BURKHALTER:··Carrying charges? 20·· · · · · · · ·MS. KELLEY:··Yes.··I'm sorry. 21·· · · · · · · ·JUDGE BURKHALTER:··Thank you. 22·· · · · · · · ·MS. KELLEY:··If you include the carrying 23··charges the Company seeks, we're approaching close to 10 24··million. 25·· · · · · · · ·But I would ask the Administrative Law KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 26 ·1··Judge to consider that given a reliance that Mr. Morris ·2··and Mr. Considine placed in their testimony, what ·3··they've described as kind of a vast and supposedly ·4··pinpoint accurate ETI cost review process -- it's no ·5··small matter if the Intervenors, with their considerable ·6··and less resources, have shown that even the allegedly ·7··small areas -- errors or unnecessary and unreasonable ·8··expenses exist.··It should cause one to believe that ·9··it's fairly easy to catch errors that are made.··Even in 10··the bill review process, it should call into question 11··the integrity of ESI's whole cost review system, but we 12··don't have the opportunity to see. 13·· · · · · · · ·Let's keep in mind that none of our state 14··regulators in any state ever sees the total picture of 15··the cost or indirect costs that are passed down to 16··ratepayers.··They're different test years.··A lot of it 17··is under seal -- most of it is under seal.··And the 18··Company's assertion through witnesses who are largely 19··pretty interested in the outcome of an infallible system 20··that passes along only reasonable costs is, in essence, 21··just a variation of "trust us." 22·· · · · · · · ·I think this is why the legislation has 23··given the Commission discretion to consider, on a 24··case-by-case basis, the entire range of what's gone on 25··in a case and whether or not the services for which the KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 27 ·1··ratepayers seem to be held responsible are justified to ·2··be passed through. ·3·· · · · · · · ·That's one reason we've proposed what's ·4··described as a radical approach.··I would put forward ·5··it's not any more radical than some of the -- what Texas ·6··disciplinary rules of professional conduct require ·7··attorneys -- requires factors to be considered in ·8··determining the reasonableness of a fee, and one of ·9··those factors is the amount involved in the results 10··obtained. 11·· · · · · · · ·We're simply asking that the investor be 12··given some skin in the game, and we think it's long 13··overdue.··Right now shareholders have nothing to lose. 14··They have no incentive to review the frequency and scope 15··of ratemaking and ancillary proceedings, for which costs 16··are also sought in base rate cases.··They have no 17··incentive to do that, but simply pass along cost of 18··whatever nature to the ratepayer. 19·· · · · · · · ·If they're given some interest -- 20··financial interest, they may more closely scrutinize the 21··priorities that the Company management decides to pursue 22··in rate cases and in ancillary proceedings. 23·· · · · · · · ·You'll notice for example -- let's compare 24··and contrast the capable folks who work for the Cities. 25··For their fees, which are considerably smaller KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 28 ·1··percentage than the rate cases that Entergy is seeking, ·2··they achieve a far greater return on the dollars they ·3··spend.··They put their priorities and limited resource ·4··to good use, but most importantly you'll also notice ·5··that the Texas Industrial Energy Consumers, whose ·6··members are actually paying the rate case expense -- it ·7··isn't passed on -- they do a very successful and ·8··efficient job on presenting targeted review. ·9·· · · · · · · ·Finally, in concluding the statute, to 10··emphasize again -- it can't be emphasized enough -- 11··gives the Commission discretion, they may allow 12··reasonable cost of participating.··So they're not 13··confined just to analyzing whether or not something is 14··reasonable.··They can look at costs and say, "Sure, that 15··was reasonable, but in this case, it's excessive." 16·· · · · · · · ·And that's what we're asking the 17··Administrative Law Judge, as well as the Commission, to 18··ultimately do.··Thank you. 19·· · · · · · · ·JUDGE BURKHALTER:··Thank you. 20·· · · · · · ··OPENING STATEMENT ON BEHALF OF 21·· · · · · ··TEXAS INDUSTRIAL ENERGY CONSUMERS 22·· · · · · · · ·MS. GRIFFITHS:··Your Honor, my comments 23··will be very brief.··We agree with the State and the 24··Office of Public Utility Commission that the recovery of 25··rate case expenses under PURA is discretionary, it's not KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 29 ·1··mandatory, and that the Commission has broad authority ·2··to determine what constitutes reasonable rate case ·3··expenses.··We think that the State and OPUC and Staff ·4··have raised good arguments and that you should consider ·5··them in this case. ·6·· · · · · · · ·JUDGE BURKHALTER:··Thank you.··Mr. Foley? ·7·· · · · · · · ·MR. FOLEY:··Staff has no opening ·8··statement, Your Honor. ·9·· · · · · · · ·JUDGE BURKHALTER:··All right. 10··Mr. Neinast, you may proceed. 11·· · · · · · · ·MR. NEINAST:··Thank you, Your Honor. 12··Commission calls to the stand Mr. Michael Considine. 13·· · · · · · · ·(Witness Considine sworn) 14·· · · · · · · ·JUDGE BURKHALTER:··Tell me your name 15··again, ma'am. 16·· · · · · · · ·MS. RIZVI:··Wajiha Rizvi representing 17··Entergy Texas. 18·· · · · · · · ·JUDGE BURKHALTER:··Would you spell that 19··last name? 20·· · · · · · · ·MS. RIZVI:··Sure.··It's R-I, Z as in 21··zebra, V as in Victor, I. 22·· · · · · · · ·JUDGE BURKHALTER:··Thank you.··Whenever 23··you're ready. 24·· · · · · · · ·MS. RIZVI:··Thank you, Your Honor. 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 30 ·1·· · ··PRESENTATION ON BEHALF OF ENTERGY TEXAS, INC. ·2·· · · · · · · · ··MICHAEL P. CONSIDINE, ·3··having been first duly sworn, testified as follows: ·4·· · · · · · · · · ··DIRECT EXAMINATION ·5··BY MS. RIZVI: ·6·· · ·Q· ··Good morning. ·7·· · ·A· ··Good morning. ·8·· · ·Q· ··Please state your name for the record. ·9·· · ·A· ··Michael Considine. 10·· · ·Q· ··Mr. Considine, do you have before you a number 11··of documents marked Entergy Texas Exhibits 1 through 7? 12·· · ·A· ··I do. 13·· · ·Q· ··Okay.··And can you go through and identify 14··these exhibits, please? 15·· · ·A· ··Exhibit 1 is my direct testimony from 16··Docket 39896 filed in November of 2011.··It's actually a 17··redacted version of that. 18·· · · · · · · ·Exhibit No. 2 is Schedule G-14.1 from 19··Docket 39896. 20·· · · · · · · ·Exhibit 3 is the rate case expense rider 21··and cost allocation tariff and supporting workpapers.··I 22··don't have the date that that was filed, but it was 23··sometime in October of this year. 24·· · · · · · · ·Exhibit 4 is my supplemental direct 25··testimony filed in March of 2012 in Docket 39896. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 31 ·1·· · · · · · · ·Exhibit 5 is supplemental direct testimony ·2··filed in October of 2012 in Docket 40295. ·3·· · · · · · · ·Exhibit 6 is another set of supplemental ·4··direct testimony filed in Docket 40295 on October 25th, ·5··2012. ·6·· · · · · · · ·And Exhibit 7 is my rebuttal testimony ·7··filed in Docket 40295 filed on November 15th, 2012. ·8·· · ·Q· ··Thank you.··And were these documents prepared ·9··by you or under your direct supervision? 10·· · ·A· ··Yes, they were. 11·· · ·Q· ··And if I were to ask you the same questions 12··that are in your testimony today, would your responses 13··be the same? 14·· · ·A· ··Yes, they would. 15·· · · · · · · ·MS. RIZVI:··Your Honor, the Company moves 16··to admit Entergy Texas Exhibits 1 through 7. 17·· · · · · · · ·JUDGE BURKHALTER:··Any objection? 18·· · · · · · · ·(No response) 19·· · · · · · · ·JUDGE BURKHALTER:··They're admitted. 20·· · · · · · · ·(Exhibit ETI Nos. 1 through 7 admitted) 21·· · · · · · · ·MR. NEINAST:··At this time, I'd like to 22··tender the witness for cross. 23·· · · · · · · ·MR. MACK:··Cities have no questions. 24·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris? 25·· · · · · · · ·MS. FERRIS:··Yes, I do have question, Your KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 32 ·1··Honor. ·2·· · · · · · · ·JUDGE BURKHALTER:··I'm sorry.··We're going ·3··to wait on you. ·4·· · · · · · · ·MS. KELLEY:··Are you going to go before ·5··Staff? ·6·· · · · · · · ·MS. FERRIS:··Right before Staff. ·7·· · · · · · · ·MS. KELLEY:··Okay. ·8·· · · · · · · ·JUDGE BURKHALTER:··So Ms. Kelley. ·9·· · · · · · · · · ··CROSS-EXAMINATION 10··BY MS. KELLEY: 11·· · ·Q· ··Mr. Considine, I just have a few questions.··If 12··we can turn to your supplemental direct -- and I think 13··both of them probably have the same page -- pagination. 14··Beginning on Page 3, 19 -- 15·· · · · · · · ·JUDGE BURKHALTER:··I'm sorry, Ms. Kelley. 16··What exhibit are you in? 17·· · · · · · · ·MS. KELLEY:··Yeah, I've got to -- 18·· · · · · · · ·JUDGE BURKHALTER:··Did you say his direct 19··testimony? 20·· · · · · · · ·MS. KELLEY:··It would be his supplemental 21··direct testimony, Exhibit 5. 22·· · ·A· ··Which page? 23·· · ·Q· ··(BY MS. KELLEY)··Let's look at Exhibit 6, 24··because that's the one I've got.··Exhibit 6, your 25··supplemental direct.··And if we can start with Page 3 at KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 33 ·1··Line 19.··It appears -- is it fair to say that your main ·2··basis for concluding that costs are reasonable and ·3··necessary in this case is the system that ESI has in ·4··place for review of the costs? ·5·· · ·A· ··Yes, ma'am, the internal controls of the ·6··Company are heavily weighed upon when deciding that the ·7··costs are reasonable and necessary. ·8·· · ·Q· ··Okay. ·9·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley, I'm sorry 10··to interrupt.··Ms. Rizvi, I have a question for you. 11·· · · · · · · ·MS. RIZVI:··Yes. 12·· · · · · · · ·JUDGE BURKHALTER:··So Exhibit 5 is 13··supplemental direct testimony of Michael Considine. 14··Exhibit 6 is supplemental direct testimony of Michael 15··Considine.··Are they different? 16·· · · · · · · ·MS. RIZVI:··Yes, Your Honor.··These 17··supplemental direct testimonies provided updates, so 18··it's actually best to identify them by date.··I think 19··that would make that a little bit more clear. 20·· · · · · · · ·MS. KELLEY:··Right.··I'm using the October 21··25th. 22·· · · · · · · ·MS. RIZVI:··Yeah, the October 25th one is 23··the one we're referring to now. 24·· · · · · · · ·JUDGE BURKHALTER:··All right. 25·· · ·Q· ··(BY MS. KELLEY)··And so to be clear, you KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 34 ·1··yourself did not go through each one of these line items ·2··that are part of ETI's overall rate case requests.··Is ·3··that fair to say? ·4·· · ·A· ··Which line items are you referring to? ·5·· · ·Q· ··Well, anything that would be on your Schedules ·6··MPC-R-1 -- anything that constitutes a rate case expense ·7··that's percolated up to you.··You didn't review each and ·8··every individual entry, did you? ·9·· · ·A· ··No, ma'am, I did not.··I did review several of 10··the invoices that are presented here. 11·· · ·Q· ··I understand. 12·· · ·A· ··And other people that work for the Company 13··reviewed the other pieces, yes, ma'am. 14·· · ·Q· ··But I know you recite this to me, along with 15··various other people, Mr. Gardner -- you have heavy 16··reliance on what they have to say about their review of 17··those costs.··Is that fair to say? 18·· · ·A· ··I do, as well as the controls the Company has 19··in place. 20·· · ·Q· ··Okay.··I want to show you what I've marked as 21··State's Exhibit No. 4. 22·· · · · · · · ·(Exhibit State Agencies No. 4 marked) 23·· · · · · · · ·MS. KELLEY:··And I apologize.··Our 24··administrative assistant is out sick today, sad to say, 25··so it's all up to me. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 35 ·1·· · ·Q· ··(BY MS. KELLEY)··Now, is this an RFI response ·2··that you sponsored regarding purchased power capacity ·3··rider costs? ·4·· · ·A· ··Yes, ma'am. ·5·· · · · · · · ·MS. KELLEY:··I offer this into evidence, ·6··Your Honor. ·7·· · · · · · · ·JUDGE BURKHALTER:··Any objection to the ·8··admission of Exhibit 4? ·9·· · · · · · · ·(No response) 10·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. 11·· · · · · · · ·(Exhibit State Agencies No. 4 admitted) 12·· · ·Q· ··(BY MS. KELLEY)··So is it fair to say the 13··system on which you relied in determining the fair and 14··reasonable cost related to purchase power has no way to 15··break out the costs that are specifically related to 16··that issue? 17·· · ·A· ··That's correct.··Employees charge their time 18··and expenses to a rate case project code that's set up 19··specifically for Docket 39896. 20·· · ·Q· ··But not issue specific? 21·· · ·A· ··No, ma'am. 22·· · ·Q· ··Now I'm going show you what I've marked as 23··State Agencies Exhibit No. 9. 24·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley, do you have 25··a batch of exhibits you want to cover with this witness? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 36 ·1··If you want to go ahead and hand them all out. ·2·· · · · · · · ·MS. KELLEY:··Okay.··I've got some of them ·3··separated.··Next time I make a pass, I'll bring them all ·4··up. ·5·· · · · · · · ·(Exhibit State Agencies No. 9 marked) ·6·· · ·Q· ··(BY MS. KELLEY)··Is this also an RFI response ·7··that you sponsored? ·8·· · ·A· ··Yes, ma'am, as well as Mr. Morris. ·9·· · ·Q· ··Okay.··And does it set out all the adjustments 10··that ETI has made to its rate case expense since direct 11··testimony was filed? 12·· · ·A· ··If you'll give me a second to just review it. 13·· · ·Q· ··Sure. 14·· · ·A· ··Yes, ma'am, it appears to. 15·· · ·Q· ··And can you tell me, sir, where those 16··adjustments have been made in this case? 17·· · ·A· ··If we would refer to my exhibit in the same set 18··of testimony, Exhibit -- well, it's marked as Page 8 in 19··Exhibit 6. 20·· · ·Q· ··And that would be the October 25th -- 21·· · ·A· ··Yes, ma'am. 22·· · ·Q· ··-- testimony? 23·· · · · · · · ·Okay.··For example, on Exhibit No. 9, if 24··you look on the second page, I believe that one thing 25··you said has come out -- if you look about midway down KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 37 ·1··that addendum response, "The Company has excluded ·2··$582.02, the total amount by which the charges for meals ·3··exceeded $25 per person, per meal." ·4·· · ·A· ··Yes, ma'am. ·5·· · ·Q· ··Can you show me where that particular deduction ·6··has been made on your schedule? ·7·· · ·A· ··I believe that that -- if you -- it does not ·8··have line numbers, but if you look under the Company -- ·9··or the consultant's bucket, there's a less 10··non-conforming expenses line for $22. 11·· · ·Q· ··Okay. 12·· · ·A· ··That plus the $560 of non-conforming expenses 13··down in the internal rate case expense line -- 14·· · ·Q· ··Okay. 15·· · ·A· ··-- is the $582. 16·· · ·Q· ··Okay.··Now I'm going to show you what I've 17··marked as Exhibit No. 5. 18·· · · · · · · ·JUDGE BURKHALTER:··Would you like to have 19··9 admitted? 20·· · · · · · · ·MS. KELLEY:··Yes, I would like to have 9 21··admitted, Your Honor. 22·· · · · · · · ·JUDGE BURKHALTER:··Any objection to 9? 23·· · · · · · · ·(No response) 24·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. 25·· · · · · · · ·(Exhibit State Agencies No. 9 admitted) KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 38 ·1·· · · · · · · ·MS. KELLEY:··And I'm going to bring you up ·2··number -- I'm going to bring up a few others at the same ·3··time. ·4·· · · · · · · ·(Exhibit State Agencies Nos. 5 and 11 ·5·· · · · · · · ·marked) ·6·· · · · · · · ·MS. KELLEY:··Your Honor, I'm a little ·7··short on No. 12, but I'll bring them up in a minute. ·8·· · · · · · · ·(Exhibit State Agencies No. 12 marked) ·9·· · ·Q· ··(BY MS. KELLEY)··Okay.··If I can ask you to 10··look at Exhibit No. 5 -- 11·· · ·A· ··Yes, ma'am. 12·· · ·Q· ··-- Mr. Considine.··Is this an RFI response that 13··you and Mr. Morris co-sponsored? 14·· · ·A· ··Yes, it is. 15·· · ·Q· ··And was it a response to Staff about how many 16··meals exceeded $25? 17·· · · · · · · ·MS. RIZVI:··Excuse me.··I did not get 18··Exhibit No. 5. 19·· · · · · · · ·MS. KELLEY:··I'm sorry.··Okay. 20·· · ·A· ··Yes, ma'am, that's what it appears to be. 21·· · ·Q· ··(BY MS. KELLEY)··Now, were you relying on the 22··same system that you did for review of costs to identify 23··these meals? 24·· · ·A· ··Yes, ma'am. 25·· · ·Q· ··Did you personally go through the receipts to KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 39 ·1··try and pull these meals out? ·2·· · ·A· ··I did not.··People that work for the Company ·3··did, though, yes, ma'am. ·4·· · ·Q· ··Okay. ·5·· · · · · · · ·MS. KELLEY:··I'd like to offer Exhibit ·6··No. 5, Your Honor. ·7·· · · · · · · ·JUDGE BURKHALTER:··Any objection? ·8·· · · · · · · ·(No response) ·9·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. 10·· · · · · · · ·(Exhibit State Agencies No. 5 admitted) 11·· · ·Q· ··(BY MS. KELLEY)··Now, Mr. Considine, if we can 12··pull out Exhibit No. 12.··By the way, do you think it's 13··possible that on Exhibit No. 5 some of those meals got 14··overlooked?··That there may be more meals out there over 15··$25 that the Company didn't disclose on its answer to 16··No. 5? 17·· · ·A· ··No, ma'am, I don't. 18·· · ·Q· ··Okay.··Can you turn to Exhibit No. 12?··Is this 19··an RFI response that you sponsored when Staff requested 20··some additional invoices from Duggins Wren Mann & 21··Romero's May 15th invoice? 22·· · ·A· ··Yes, it is. 23·· · ·Q· ··Okay.··Now, Mr. Considine, can we turn to -- 24··what's numbered as Page 3 down in the corner? 25·· · ·A· ··Okay. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 40 ·1·· · ·Q· ··Does it appear that these receipts include a ·2··request for reimbursement from Duggins Wren attorney ·3··Scott Olson? ·4·· · ·A· ··It appears that way. ·5·· · ·Q· ··Okay.··Could you please flip to Page No. 7, ·6··sir?··Now we appear to have some restaurant receipts. ·7··Can you identify if there are any meals on Page 7 that ·8··are in excess of $25? ·9·· · ·A· ··Yes, there are.··There are -- well, exactly 10··three. 11·· · ·Q· ··Okay.··Can you find those in the response to 12··RFI 9-9, shown on State's Exhibit No. 5?··Are they 13··listed on that exhibit? 14·· · ·A· ··I'll have to review State 5 again. 15·· · ·Q· ··Okay. 16·· · ·A· ··I do not see those specifically, no, ma'am. 17·· · ·Q· ··Okay.··So those aren't on here, and that's just 18··one invoice, then. 19·· · · · · · · ·MS. KELLEY:··Your Honor, I'd like to offer 20··State Agency Exhibit No. 12. 21·· · · · · · · ·JUDGE BURKHALTER:··Any objection? 22·· · · · · · · ·(No response) 23·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. 24·· · · · · · · ·(Exhibit State Agencies No. 12 admitted) 25·· · ·Q· ··(BY MS. KELLEY)··Now, do you have State's KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 41 ·1··Exhibit No. 11?··Is that one of the ones I brought up ·2··there? ·3·· · ·A· ··I do. ·4·· · ·Q· ··Good.··Okay.··Is this also an RFI response that ·5··you sponsored? ·6·· · ·A· ··Along with Mr. Morris, yes. ·7·· · · · · · · ·MS. KELLEY:··Okay.··Your Honor, I'd like ·8··to offer this into evidence. ·9·· · · · · · · ·JUDGE BURKHALTER:··Any objection? 10·· · · · · · · ·(No response) 11·· · ·Q· ··(BY MS. KELLEY)··Now, is it fair to say -- 12·· · · · · · · ·JUDGE BURKHALTER:··Hang on a second.··Let 13··me make sure there's no objection. 14·· · · · · · · ·MS. KELLEY:··Okay. 15·· · · · · · · ·JUDGE BURKHALTER:··Ms. Rizvi, do you have 16··any objection to Exhibit 11? 17·· · · · · · · ·MS. RIZVI:··No, Your Honor. 18·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. 19·· · · · · · · ·(Exhibit State Agencies No. 11 admitted) 20·· · ·Q· ··(BY MS. KELLEY)··Is it fair to say that the 21··Company doesn't regard those items as luxury items, that 22··that's the gist of your answer? 23·· · ·A· ··Yes, ma'am.··Bottled water, the Company in this 24··RFI doesn't consider to be a luxury item. 25·· · ·Q· ··Okay.··But I think that response says that all KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 42 ·1··of those items at this point the Company doesn't agree ·2··are luxury items.··Is that fair to say? ·3·· · ·A· ··It says, "The Company disagrees with the ·4··premise that each of the examples in this question ·5··constitute a luxury item." ·6·· · ·Q· ··Okay.··And is it fair to say that there hasn't ·7··been a deduction from rate case expense for any of these ·8··items? ·9·· · ·A· ··For the two items listed here, the -- 10·· · ·Q· ··Well, for any items that would -- 11·· · ·A· ··-- $5 -- 12·· · ·Q· ··-- qualify as luxury items; bottled water -- 13·· · · · · · · ·JUDGE BURKHALTER:··You're referring to the 14··items listed in your question.··Correct? 15·· · · · · · · ·MS. KELLEY:··Your Honor, I'm referring 16··to -- 17·· · · · · · · ·JUDGE BURKHALTER:··The items listed in the 18··question, not in the response.··Is that correct? 19·· · · · · · · ·MS. KELLEY:··Yes, the items in the 20··question.··Yes, Your Honor. 21·· · ·A· ··The Company makes an effort to remove any items 22··like this.··I can't say that there are items like this 23··that the Company is requesting either. 24·· · ·Q· ··(BY MS. KELLEY)··And is it possible there may 25··be bottled water costs, for example, that were missed KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 43 ·1··that are not included on State Exhibit No. 11? ·2·· · ·A· ··Yes, ma'am, that's possible. ·3·· · ·Q· ··Out of curiosity, would you think that ·4··purchases of clothing by an attorney who is working on a ·5··case, should that be passed through as a rate case ·6··expense? ·7·· · ·A· ··No, ma'am, I wouldn't think so. ·8·· · · · · · · ·MS. KELLEY:··I have no further questions, ·9··Your Honor.··I pass the witness. 10·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you. 11··Ms. Griffiths? 12·· · · · · · · ·MS. GRIFFITHS:··No questions, Your Honor. 13·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris? 14·· · · · · · · ·MS. FERRIS:··Yes, Your Honor.··Thank you. 15·· · · · · · · ·(Exhibit OPUC No. 2 marked) 16·· · · · · · · · · ··CROSS-EXAMINATION 17··BY MS. FERRIS: 18·· · ·Q· ··Good morning, Mr. Considine. 19·· · ·A· ··Good morning. 20·· · ·Q· ··I've handed you what's been marked as OPUC 21··Exhibit No. 2.··Do you have it? 22·· · ·A· ··I do. 23·· · ·Q· ··And were you the sponsoring witness for two of 24··the three questions contained in this response? 25·· · ·A· ··I was. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 44 ·1·· · ·Q· ··Thank you.··Question No. 3-1(c) asks you a ·2··question about Robert Cooper.··Is that correct? ·3·· · ·A· ··Yes, ma'am. ·4·· · ·Q· ··What was the subject of Robert Cooper's ·5··testimony? ·6·· · ·A· ··His overall direct testimony in the rate case? ·7·· · ·Q· ··Yes, sir. ·8·· · ·A· ··He discussed basically the system planning ·9··process for purchase power. 10·· · ·Q· ··Would you characterize him as a major witness 11··on the purchase power issue? 12·· · ·A· ··I would. 13·· · ·Q· ··Would that also include third party purchase 14··power agreements? 15·· · ·A· ··Yes, it would. 16·· · ·Q· ··And on the second question, 3-2, on Subquestion 17··(b), we ask you about the test -- about the attorney 18··Dick Westerburg.··Are you familiar with Mr. Westerburg? 19·· · ·A· ··I am. 20·· · ·Q· ··What's his title with the Company? 21·· · ·A· ··I don't know his specific title.··He's an 22··attorney with the Company. 23·· · ·Q· ··Okay.··He was the attorney who was in charge of 24··Mr. Cooper's testimony.··Is that correct? 25·· · ·A· ··I don't know that. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 45 ·1·· · ·Q· ··Do you know whether he handled the direct ·2··examination of Mr. Cooper during the hearing on the ·3··merits in 39896? ·4·· · ·A· ··I was not in the room, so I don't know that he ·5··did. ·6·· · ·Q· ··Do you know if he was the attorney for the ·7··deposition of Mr. Cooper in that docket? ·8·· · ·A· ··I do not. ·9·· · ·Q· ··Regarding Mr. Cooper's testimony, I believe 10··your response to Question (b) of 3-1 was that -- well, 11··actually, more generally in Question (c) and 12··Question (b), did the Company respond that they did 13··not -- could not reasonably estimate the percentage of 14··expenses related to capacity purchase?··Is that right? 15·· · ·A· ··That's a fair statement. 16·· · ·Q· ··And they could not -- you could not tell us 17··what part of Mr. Cooper's expenses related to his 18··testimony were related to purchase power or to third 19··party purchase power agreements.··Is that right? 20·· · ·A· ··That's correct.··The Company tracks time on a 21··project level basis, and the entire project related to 22··the rate case as a whole. 23·· · ·Q· ··And we asked you to make the best efforts to 24··estimate the percentage of time, and the Company was not 25··able to do so.··Is that right? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 46 ·1·· · ·A· ··Yes, ma'am.··I personally was not going to ·2··guess. ·3·· · ·Q· ··Okay.··And the same is true for the time of ·4··Mr. Westerburg.··Is that correct? ·5·· · ·A· ··That's correct. ·6·· · · · · · · ·MS. FERRIS:··Your Honor, at this time, we ·7··offer OPUC Exhibit No. 2. ·8·· · · · · · · ·JUDGE BURKHALTER:··Any objection? ·9·· · · · · · · ·(No response) 10·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. 11·· · · · · · · ·(Exhibit OPUC No. 2 admitted) 12·· · · · · · · ·MS. FERRIS:··And I pass the witness. 13·· · · · · · · ·JUDGE BURKHALTER:··Mr. Foley? 14·· · · · · · · ·MR. FOLEY:··Staff has no questions. 15·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Redirect? 16·· · · · · · · ·MS. RIZVI:··Thank you. 17·· · · · · · · · · ·REDIRECT EXAMINATION 18··BY MS. RIZVI: 19·· · ·Q· ··Mr. Considine, going back to State Agencies 20··Exhibit No. 5.··Would you pull that up? 21·· · ·A· ··I have it. 22·· · ·Q· ··Okay.··So these amounts and these charges that 23··you see, do you know whether these are the total meals 24··going over $25 or the amount by which it goes over $25? 25·· · ·A· ··It's just the incremental amount above $25. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 47 ·1·· · ·Q· ··So these are not the totals? ·2·· · ·A· ··That's my understanding. ·3·· · ·Q· ··Counsel for OPC just now was asking you the ·4··subject matter of Mr. Cooper's testimony.··Do you ·5··know -- could you repeat that, the subject matter that ·6··his testimony covers? ·7·· · ·A· ··Mr. Cooper basically covers system planning as ·8··a whole for generation. ·9·· · ·Q· ··Would you say that's a wide breadth of areas 10··covered? 11·· · ·A· ··Yes, it is. 12·· · ·Q· ··And do you know the position that Mr. Cooper 13··holds with the Company? 14·· · ·A· ··I believe he's the manager of generation 15··planning I think is his specific title. 16·· · ·Q· ··Okay.··Now, can you please explain how Company 17··employees charge their time to the rate case project 18··code? 19·· · ·A· ··Sure.··For an example, I, myself, am an Entergy 20··Services employee and charge time based on the hours I 21··spend to the specific project code set up for this rate 22··case, and that time is billed 100 percent to Entergy 23··Texas, because it's a Texas specific rate case.··My time 24··is approved by my supervisor.··I have direct supports 25··that I approve time for.··So there are internal controls KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 48 ·1··within the Company to make sure that the time being ·2··reported by every employee is correctly charged.··And ·3··the only dollars that the Company is requesting in this ·4··docket are the charges charged to that specific project ·5··code.··There's no double recovery, if you will, that's ·6··being suggested. ·7·· · · · · · · ·MS. RIZVI:··Pass the witness. ·8·· · · · · · · ·JUDGE BURKHALTER:··Mr. Mack? ·9·· · · · · · · ·MR. MACK:··No questions. 10·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley? 11·· · · · · · · ·MS. KELLEY:··No questions. 12·· · · · · · · ·JUDGE BURKHALTER:··Ms. Griffiths? 13·· · · · · · · ·MS. GRIFFITHS:··No questions. 14·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris? 15·· · · · · · · ·MS. FERRIS:··Yes, Your Honor. 16·· · · · · · · ·JUDGE BURKHALTER:··Go ahead. 17·· · · · · · · · · ·RECROSS-EXAMINATION 18··BY MS. FERRIS: 19·· · ·Q· ··Mr. Considine, your attorney just asked you a 20··follow-up question regarding the subject matter of 21··Mr. Cooper's testimony.··Do you recall that? 22·· · ·A· ··Yes, I do. 23·· · ·Q· ··Purchase power was a large part of the request 24··that was sponsored by -- that was sponsored by 25··Mr. Cooper.··Is that correct? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 49 ·1·· · · · · · · ·MS. RIZVI:··Objection, Your Honor. ·2··Counsel is testifying. ·3·· · · · · · · ·JUDGE BURKHALTER:··Overruled. ·4·· · ·A· ··Can you repeat the question? ·5·· · ·Q· ··(BY MS. FERRIS)··Yes.··Purchase power was a ·6··large portion of that system planning testimony that ·7··Mr. Cooper asked.··Correct? ·8·· · ·A· ··In addition to talking in generalities about ·9··generation planning as a whole, Mr. Cooper did 10··specifically address purchase power, yes. 11·· · ·Q· ··Wasn't the Company's request on purchase power 12··worth between 20 and $30 million? 13·· · ·A· ··As part of the overall rate request, yes, it 14··was. 15·· · ·Q· ··Do you know -- but the Company has no idea what 16··percentage of Mr. Cooper's testimony was spent on the 17··purchase power issues? 18·· · ·A· ··No.··Mr. Cooper would have charged the general 19··rate case project code for that time. 20·· · ·Q· ··It could have been five minutes or 500 hours. 21··Correct? 22·· · ·A· ··And that's why -- 23·· · · · · · · ·MS. RIZVI:··Objection, Your Honor.··This 24··calls for speculation. 25·· · · · · · · ·JUDGE BURKHALTER:··Overruled. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 50 ·1·· · · · · · · ·MS. FERRIS:··Pass the witness.··Oh, I'm ·2··sorry. ·3·· · · · · · · ·JUDGE BURKHALTER:··Do you want an answer? ·4·· · · · · · · ·MS. FERRIS:··I wanted him to answer.··I ·5··withdraw my pass. ·6·· · ·A· ··I don't know the answer to that question. ·7·· · · · · · · ·MS. FERRIS:··Now I pass.··Thank you, Your ·8··Honor. ·9·· · · · · · · ·JUDGE BURKHALTER:··Mr. Foley? 10·· · · · · · · ·MR. FOLEY:··No questions. 11·· · · · · · · ·JUDGE BURKHALTER:··Ms. Rizvi? 12·· · · · · · · ·MS. RIZVI:··Pass the witness. 13·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you, 14··Mr. Considine.··You may step down.··Ms. Rizvi, who is 15··your next witness? 16·· · · · · · · ·MS. RIZVI:··We call Stephen Morris to the 17··stand, please. 18·· · · · · · · ·(Witness Morris sworn) 19·· · · · · · · ·JUDGE BURKHALTER:··And tell me your name 20··again, sir. 21·· · · · · · · ·MR. HOYT:··George Hoyt for the Company. 22·· · · · · · · ·JUDGE BURKHALTER:··Thank you. 23·· 24·· 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 51 ·1·· · · · · · · · · ··STEPHEN F. MORRIS, ·2··having been first duly sworn, testified as follows: ·3·· · · · · · · · · ··DIRECT EXAMINATION ·4··BY MR. HOYT: ·5·· · ·Q· ··Good morning. ·6·· · ·A· ··Good morning. ·7·· · ·Q· ··Could you state your name for the record, ·8··please? ·9·· · ·A· ··Stephen F. Morris. 10·· · ·Q· ··Do you have before you what have been marked 11··ETI Exhibits 8 through 12? 12·· · ·A· ··Yes, sir. 13·· · ·Q· ··Can you explain what each of these exhibits 14··are? 15·· · ·A· ··Yes, sir.··Starting with Exhibit 8, it is my 16··direct testimony that was filed in Docket 39896, which 17··was the underlying rate case, in November of 2011. 18·· · · · · · · ·ETI Exhibit 9 is my supplemental direct 19··testimony, also filed in Docket 39896, in March of 2012. 20·· · · · · · · ·Exhibit 10 is my supplemental direct 21··testimony in this docket, 40295, that was filed in 22··October of 2012.··That would be October 5th, 2012. 23·· · · · · · · ·ETI Exhibit 11 is my supplemental direct 24··testimony filed in this docket, 40295, on October 25th, 25··2012. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 52 ·1·· · · · · · · ·And finally, ETI Exhibit 12 is my rebuttal ·2··testimony filed in this docket, 40295, on November 15th, ·3··2012. ·4·· · ·Q· ··Okay.··Thank you.··And was your testimony ·5··prepared by you or under your direct supervision? ·6·· · ·A· ··Yes, sir, it was. ·7·· · ·Q· ··Do you have any corrections to any of these ·8··pieces of testimony at this time? ·9·· · ·A· ··I have a correction on Exhibit 12, which is my 10··rebuttal testimony.··If you would, please turn to 11··Page 7, Line 13.··There are two percentages on Line 13, 12··14.3 percent -- 13·· · · · · · · ·JUDGE BURKHALTER:··I'm sorry.··Are you on 14··the handwritten page number or the -- 15·· · ·A· ··I'm sorry.··The top right number.··Page 7 of 16··14. 17·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Thank you. 18·· · ·A· ··On Line 13, there were two percentages, both 19··14.3 percent.··That is a typographical error.··It should 20··be 14.5 percent as referenced in the question 21··immediately above.··Should I make that correction on 22··this copy? 23·· · ·Q· ··(BY MR. HOYT)··That would be fine. 24·· · ·A· ··Okay. 25·· · · · · · · ·JUDGE BURKHALTER:··And will you make the KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 53 ·1··same correction on the record copy, Mr. Hoyt?··Or maybe ·2··you already have. ·3·· · · · · · · ·MR. HOYT:··We will. ·4·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you. ·5·· · ·Q· ··(BY MR. HOYT)··Okay.··And with those ·6··corrections, is your written testimony a true and ·7··accurate representation of what it would be if I asked ·8··you the same questions today? ·9·· · ·A· ··Yes, sir. 10·· · ·Q· ··Okay. 11·· · · · · · · ·MR. HOYT:··And with that, ETI moves to 12··admit Exhibits 8 through 12 into the record. 13·· · · · · · · ·JUDGE BURKHALTER:··Any objection? 14·· · · · · · · ·MS. FERRIS:··Yes, Your Honor.··Actually, 15··subject to optional completeness on Exhibit No. 12.··And 16··we have an exhibit we could offer that would exercise 17··that. 18·· · · · · · · ·JUDGE BURKHALTER:··All right.··Any other 19··objections? 20·· · · · · · · ·(No response) 21·· · · · · · · ·JUDGE BURKHALTER:··They're admitted. 22·· · · · · · · ·(Exhibit ETI Nos. 8 through 12 admitted) 23·· · · · · · · ·MR. HOYT:··At this time, we tender for 24··cross. 25·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Mr. Mack? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 54 ·1·· · · · · · · ·MR. MACK:··Cities have no questions, Your ·2··Honor. ·3·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley? ·4·· · · · · · · ·MS. KELLEY:··I do.··Again, I have some ·5··exhibits. ·6·· · · · · · · ·(Exhibit State Agencies Nos. 2, 6, 7, 8, ·7·· · · · · · · ·14, 15, 17 marked) ·8·· · · · · · · · · ··CROSS-EXAMINATION ·9··BY MS. KELLEY: 10·· · ·Q· ··Okay.··Mr. Morris, I'd like to start by asking 11··about your own firm's arrangement for services in the 12··case.··Now, Naman Howell entered into a contract with 13··the Duggins Wren law firm and with Entergy.··Is that 14··correct. 15·· · ·A· ··Yes, ma'am. 16·· · ·Q· ··Okay.··And is it fair to say that Duggins Wren 17··entered into contracts with most of the outside 18··consultants and experts in this case? 19·· · ·A· ··I believe it entered into a contract with some 20··of them, yes. 21·· · ·Q· ··Okay.··But everybody that's the subject of your 22··testimony or review, were those pretty much direct 23··contracts with Duggins Wren? 24·· · ·A· ··Some of them were, yes. 25·· · ·Q· ··Okay.··Now, did you review contracts as part of KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 55 ·1··your own bill and review? ·2·· · ·A· ··The consulting services agreement? ·3·· · ·Q· ··Yes, sir. ·4·· · ·A· ··I did. ·5·· · ·Q· ··Okay.··And if you can, look at Exhibit No. 15. ·6··Is that part of your packet? ·7·· · ·A· ··Yes, it is. ·8·· · ·Q· ··Okay.··And I want to emphasize that this was a ·9··public contract.··It was disclosed publically.··It was 10··an RFI response. 11·· · · · · · · ·Is this a copy of your contract with 12··Duggins Wren? 13·· · ·A· ··Yes, it is. 14·· · · · · · · ·MS. KELLEY:··Okay.··I would like to offer 15··Exhibit 15 into evidence, Your Honor. 16·· · · · · · · ·JUDGE BURKHALTER:··Any objection? 17·· · · · · · · ·(No response) 18·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. 19·· · · · · · · ·(Exhibit State Agencies No. 15 admitted) 20·· · ·Q· ··(BY MS. KELLEY)··Now, are the contracts that 21··Duggins Wren has entered into with outside consultants, 22··are they fairly standard on how meals and outside 23··expenses are handled? 24·· · ·A· ··I believe they are, yes. 25·· · ·Q· ··Okay.··So is that contract language in your KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 56 ·1··contract typical of other contracts that they entered ·2··into with the consultants? ·3·· · ·A· ··Without having whatever other unnamed contracts ·4··that you're talking about in front of me, I -- subject ·5··to check, I believe so. ·6·· · ·Q· ··Okay.··Subject to check.··For example, you ·7··couldn't bill Duggins Wren for meals you had working out ·8··of your own office during a regular day, could you? ·9·· · ·A· ··Conceivably, yes, if we were having a working 10··lunch where there would be, say, a meeting to go over 11··rate case items. 12·· · ·Q· ··Well, I understand what you're saying, but I 13··meant you particularly -- let me be a little more clear. 14·· · · · · · · ·When you're at your desk and not at a 15··meeting with anybody else, could you typically bill for 16··some of your lunch during the ordinary working day? 17·· · ·A· ··If I personally worked through lunch, I didn't 18··bill Duggins Wren for a meal. 19·· · ·Q· ··Okay.··How about snacks that you get at your 20··desk during an ordinary working day?··If you're snacking 21··on peanuts or popcorn or snack crackers, is that 22··something that you would bill through to them? 23·· · ·A· ··One of the legal assistants in our office has a 24··little snack jar, and if I -- I don't usually eat 25··snacks, but if I do, I'll just go over and get one out KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 57 ·1··of her jar. ·2·· · ·Q· ··Okay.··Well, that's a good way to handle that. ·3··But does she turn in receipts to you for reimbursements ·4··for that? ·5·· · ·A· ··No.··I believe lately it's been leftover ·6··Halloween candy. ·7·· · ·Q· ··Okay.··Can I ask you to look at State Agencies ·8··Exhibits No. 6 and 7 that you sponsored?··Are these ·9··answers true and correct still?··I mean, you've not 10··filed an addendum to either of these answers.··Is that 11··fair to say? 12·· · · · · · · ·MR. HOYT:··Which one is 7, Sue? 13·· · · · · · · ·(Simultaneous discussion) 14·· · ·Q· ··(BY MS. KELLEY)··Do you have 6 and 7, sir? 15·· · ·A· ··I do. 16·· · ·Q· ··Okay.··And I think I said these answers are 17··still true and correct? 18·· · ·A· ··They are. 19·· · · · · · · ·MS. KELLEY:··Okay.··I'd like to offer 20··these into evidence, please. 21·· · · · · · · ·JUDGE BURKHALTER:··Any objection to 22··admission of 6 and 7? 23·· · · · · · · ·MR. HOYT:··No. 24·· · · · · · · ·JUDGE BURKHALTER:··They're admitted. 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 58 ·1·· · · · · · · ·(Exhibit State Agencies Nos. 6 and 7 ·2·· · · · · · · ·admitted) ·3·· · ·Q· ··(BY MS. KELLEY)··Now, if we could turn to ·4··Exhibit No. 7, Mr. Morris, I see that you attached some ·5··emails to your staff.··By the way, what's -- what is the ·6··billing rate for your staff if they worked on a case ·7··project for this particular case? ·8·· · ·A· ··(No audible response) ·9·· · ·Q· ··Okay.··We're looking at No. 7 right now. 10·· · ·A· ··I believe it's $70 an hour. 11·· · ·Q· ··Okay.··Take a look at the last page of No. 7. 12··It refers -- counsels one of your assistants to review 13··them using the ETI checklist.··What's the ETI checklist? 14·· · ·A· ··That is a checklist that I use in reviewing the 15··invoices that I review that can -- it has, say, a check 16··list or punch list of items.··Are the rates in 17··conformance with the consulting services agreement? 18··Were there more than 12 hours spent on any one day? 19··Were there any, say, meals over $25 or luxury items, you 20··know, in-room hotel movies, first class airfare, things 21··like that, that helps facilitate my review of the 22··invoices. 23·· · ·Q· ··To your knowledge, is that ETI checklist -- was 24··that produced in response to any discovery requests in 25··this case? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 59 ·1·· · ·A· ··I don't believe it was requested, no, ma'am. ·2·· · ·Q· ··Okay.··But you'll agree that the Company was ·3··requested to furnish all documents that you referred -- ·4··in RFI No. 6 in the rate case, you'll agree that we ·5··asked for production of all documents upon which their ·6··expert witnesses relied.··Is that correct? ·7·· · · · · · · ·No, not our Exhibit 6, but during the rate ·8··case, the Company was asked to produce all documents ·9··upon which their experts relied.··Do you know -- 10·· · ·A· ··Okay. 11·· · ·Q· ··-- that to be true? 12·· · ·A· ··I believe I furnished that to Duggins Wren as 13··part of doing my review.··I'm not aware of it being 14··produced. 15·· · ·Q· ··Okay.··The checklist wasn't produced as far as 16··we know.··Is that a fair summary of what you just said? 17·· · ·A· ··I don't know if it was produced. 18·· · ·Q· ··Okay.··Now, what instruction did you give your 19··Staff as to how to assess whether charges were 20··reasonable or necessary over and above what you've 21··already described? 22·· · ·A· ··My staff would do -- perform more of a factual 23··evaluation.··You know, were more than 12 hours spent on 24··one day?··Were any meals more than $25?··I mean, things 25··like that. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 60 ·1·· · · · · · · ·The reasonable -- and the evaluation of ·2··the reasonableness of those expenses was something that ·3··I performed.··I did not delegate that to staff. ·4·· · ·Q· ··Okay.··Now, I realize it's already included in ·5··Exhibit 1, but I have demonstrative Exhibit No. 2.··I ·6··think you were just looking at that a moment ago.··Can ·7··you identify what these documents are in State Exhibit ·8··No. 2? ·9·· · ·A· ··They are invoices from Naman Howell to Duggins 10··Wren regarding the ETI rate case matter. 11·· · ·Q· ··And these would be bills for your services.··Is 12··that correct? 13·· · ·A· ··Yes, ma'am. 14·· · ·Q· ··Now, there are no time sheets or memorandum 15··containing information about your services beyond what's 16··reflected in these invoices.··Is that correct to say? 17·· · ·A· ··That's correct. 18·· · ·Q· ··Okay.··So what you see is what you get on these 19··bills? 20·· · ·A· ··That's right.··What's reflected on the bills is 21··what I have on my time sheets. 22·· · ·Q· ··Okay.··Now, let's turn to Page No. -- well, it 23··says Page No. 8 on the bottom in this exhibit.··And I'll 24··explain it starts with No. 3 because when these were 25··copied, inadvertently one document was copied twice.··So KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 61 ·1··that's why we started with Page No. 3.··But if you look ·2··at Page No. 8, sir. ·3·· · ·A· ··Okay. ·4·· · ·Q· ··We can conclude from your previous answer that ·5··this is an accurate representation of the services that ·6··you rendered.··Is that correct? ·7·· · ·A· ··Yes, ma'am. ·8·· · ·Q· ··And as well as the person who performed the ·9··services as designated by those initials? 10·· · ·A· ··That would be me, yes, ma'am. 11·· · ·Q· ··Okay.··Now, if you can, look at Exhibit No. 8, 12··State's Exhibit No. -- 13·· · · · · · · ·MS. KELLEY:··Your Honor, I would like to 14··offer No. 2, if I did not do so already. 15·· · · · · · · ·JUDGE BURKHALTER:··You did not, and I'll 16··take it now.··Any objection? 17·· · · · · · · ·MR. HOYT:··No. 18·· · · · · · · ·JUDGE RIGHT:··It's admitted. 19·· · · · · · · ·(Exhibit State Agencies No. 2 admitted) 20·· · · · · · · ·MS. KELLEY:··If we could, turn to Exhibit 21··No. 8, Your Honor. 22·· · ·Q· ··(BY MS. KELLEY)··And, Mr. Morris, can I confirm 23··that this is your response to a State of Texas RFI that 24··asked about that particular billing? 25·· · ·A· ··RFI 10-11? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 62 ·1·· · ·Q· ··Yes. ·2·· · ·A· ··It is, yes, ma'am. ·3·· · · · · · · ·MS. KELLEY:··I'd like to offer Exhibit ·4··No. 8. ·5·· · · · · · · ·JUDGE BURKHALTER:··Any objection? ·6·· · · · · · · ·MR. HOYT:··No, Your Honor. ·7·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. ·8·· · · · · · · ·(Exhibit State Agencies No. 8 admitted) ·9·· · ·Q· ··(BY MS. KELLEY)··Okay.··Now, Mr. Morris, in 10··your direct testimony, I believe it's Page 11 of what I 11··have, beginning on Line No. 18, you talk about how you 12··reviewed the hourly rate. 13·· · ·A· ··Which exhibit? 14·· · · · · · · ·MS. KELLEY:··It's his direct testimony, 15··Your Honor. 16·· · · · · · · ·JUDGE BURKHALTER:··His direct testimony? 17·· · · · · · · ·MS. KELLEY:··Yes. 18·· · · · · · · ·JUDGE BURKHALTER:··Thank you. 19·· · · · · · · ·MS. KELLEY:··What is the exhibit number? 20··It's ETI -- 21·· · · · · · · ·JUDGE BURKHALTER:··8. 22·· · · · · · · ·MS. KELLEY:··8.··That's right. 23·· · ·Q· ··(BY MS. KELLEY)··And let me know when you're 24··there. 25·· · ·A· ··On Page 11? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 63 ·1·· · ·Q· ··Page 11. ·2·· · ·A· ··Yes, ma'am, I'm there. ·3·· · ·Q· ··And Line 18, rather, not Line 8.··Where you ·4··begin to discuss how you evaluated the rates of Duggins ·5··Wren law firm. ·6·· · ·A· ··Yes. ·7·· · ·Q· ··Okay.··Now, you go on to say that you took ·8··these rates from the Texas Lawyer 2011 hourly billing ·9··survey.··And I believe I've handed out what we've marked 10··as State Exhibit No. 14.··And I want to confirm that 11··that's the billing survey that you relied upon? 12·· · ·A· ··It is, yes. 13·· · ·Q· ··Okay. 14·· · · · · · · ·MS. KELLEY:··I'd like to offer Exhibit 15··No. 14, Your Honor. 16·· · · · · · · ·JUDGE BURKHALTER:··Any objection? 17·· · · · · · · ·MR. HOYT:··Subject to optional 18··completeness -- I'm not sure if this is the whole 19··survey.··I have one page. 20·· · · · · · · ·MS. KELLEY:··Right.··That's what your 21··office provided me yesterday when I asked -- 22·· · · · · · · ·MR. HOYT:··Is it?··Okay.··No objection. 23·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. 24·· · · · · · · ·(Exhibit State Agencies No. 14 admitted) 25·· · · · · · · ·MS. KELLEY:··If there are more, I'm glad KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 64 ·1··to look -- ·2·· · · · · · · ·MR. HOYT:··I just wanted to make sure that ·3··was what the -- ·4·· · ·A· ··That is it, yes. ·5·· · · · · · · ·MR. HOYT:··Okay. ·6·· · ·Q· ··(BY MS. KELLEY)··Okay.··And I believe you say ·7··on Page 12 of your testimony -- no.··Actually, it is on ·8··Page 11.··You say on Line 21 that you compared the ·9··Duggins Wren rates against the average hourly rates of 10··firms of the size that typically represent utilities in 11··rate applications.··If we look at Exhibit No. 4, can we 12··agree that this hourly billing survey is not restricted 13··to utility attorneys? 14·· · ·A· ··I'm sorry.··I don't have an Exhibit 4. 15·· · ·Q· ··That's the Texas -- I'm sorry.··14.··You're 16··right. 17·· · ·A· ··Oh. 18·· · ·Q· ··That's the Texas Lawyer -- 19·· · ·A· ··Okay. 20·· · ·Q· ··-- hourly billing rate.··There's nothing on 21··that that restricts the survey to utility attorneys. 22··Isn't that correct? 23·· · ·A· ··No.··It distinguishes them by size of -- by 24··firm size and by location. 25·· · ·Q· ··Yes, I understand.··How many firms does KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 65 ·1··Exhibit 14 say took part in that survey? ·2·· · ·A· ··Could you repeat that? ·3·· · ·Q· ··On Exhibit No. 14, how many firms took part in ·4··this survey? ·5·· · ·A· ··I don't know. ·6·· · ·Q· ··Let me call your attention at the very bottom ·7··where it says "source." ·8·· · ·A· ··Oh, I'm sorry.··Yes.··101 firms.··I'm sorry. ·9·· · ·Q· ··Okay.··And for all we know, there could be bond 10··attorneys, personal injury attorneys, tax attorneys that 11··are included in this 101 firms.··Isn't that correct? 12·· · ·A· ··It could, certainly. 13·· · ·Q· ··Okay.··Do you have a feel for how many firms 14··there are in Texas? 15·· · · · · · · ·MR. HOYT:··Objection; calls for 16··speculation. 17·· · · · · · · ·MS. KELLEY:··Well, he's the expert. 18·· · · · · · · ·JUDGE BURKHALTER:··Right.··Overruled. 19·· · ·A· ··At least 101. 20·· · ·Q· ··(BY MS. KELLEY)··Oh, okay.··Well, that's -- and 21··I believe -- but I think we can conclude there are 22··probably more than 101 firms.··Isn't that fair to say? 23··Thousands? 24·· · ·A· ··I think you may be right, Counselor, but in my 25··25 years of experience in dealing with PUC matters, KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 66 ·1··there's a fairly small set of firms that actually ·2··practice before the Commission.··It's certainly less ·3··than 101. ·4·· · ·Q· ··Okay. ·5·· · ·A· ··You know, at least that represent utilities. ·6·· · ·Q· ··That's fine.··But this is the document that ·7··your testimony says -- this is the metric that you used ·8··in assessing whether or not the Duggins Wren law firm ·9··charges were reasonable? 10·· · ·A· ··That's right. 11·· · ·Q· ··Okay.··And I believe you said that firms that 12··typically represent investor-owned utilities have more 13··than 100 lawyers.··Did you make that statement on 14··Page 12 of your testimony? 15·· · ·A· ··That's correct. 16·· · ·Q· ··Okay.··And you represent -- I believe your 17··resume says that you represent investor-owned utilities. 18··Fair to say? 19·· · ·A· ··That's right. 20·· · ·Q· ··Okay.··But Naman Howell has only slightly over 21··60 attorneys in six cities.··Is that correct? 22·· · ·A· ··That's correct. 23·· · ·Q· ··Well, let's move to another topic.··It was part 24··of your job to review requests for reimbursement that 25··Duggins Wren employees turned into the Company that were KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 67 ·1··attached to their bills.··Is that correct? ·2·· · ·A· ··Yes, ma'am. ·3·· · ·Q· ··And is it the policy that an employee can't get ·4··reimbursed without having a receipt for that expense? ·5·· · ·A· ··I believe that is their policy. ·6·· · ·Q· ··Now, we know that alcoholic beverages shouldn't ·7··be charged to the ratepayers.··That's correct, isn't it? ·8·· · ·A· ··That's correct. ·9·· · ·Q· ··And if somebody brings a family member, those 10··costs won't be charged to the ratepayer as well, if 11··they're caught.··Is that correct? 12·· · ·A· ··Yes. 13·· · ·Q· ··In your opinion, is it reasonable to charge 14··ratepayers if a lawyer has dry cleaning or laundry 15··services that they say are related to the case?··Would 16··that be fair for them to pass that on as an expense to 17··the ratepayers? 18·· · ·A· ··I have personal experience -- I had a hearing 19··that went beyond one week, unbeknownst to me up in 20··Jefferson City, Missouri, many years ago, and on 21··Friday -- I had brought a week's worth of clothes for 22··the hearing, and it was going to pick up the following 23··Monday, so I spent the weekend in Jefferson City and 24··went down to the laundry and had that done and, you 25··know, got reimbursed for that.··So, yes.··I mean, there KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 68 ·1··are instances where, you know, it's reasonable for ·2··someone to be reimbursed for, you know, laundry, dry ·3··cleaning expenses, you know, whatever you want to call ·4··it. ·5·· · ·Q· ··Oh.··When you say you went to the laundry, you ·6··went down and you fed quarters in the machine yourself? ·7·· · ·A· ··I did, down on Missouri Boulevard. ·8·· · ·Q· ··Okay.··And I believe you said that was in ·9··relation to your attendance at a hearing.··Is that 10··correct? 11·· · ·A· ··Yes, ma'am. 12·· · ·Q· ··If you're not in attendance at a hearing, there 13··might be a different standard that would apply.··Is that 14··fair to say? 15·· · ·A· ··I think it depends on the circumstances. 16·· · ·Q· ··Okay.··Now, I believe we have Exhibit No. 5 17··that Mr. Considine talked about, and that was to 18··identify meals in excess of $25.··And you were a 19··co-sponsor for that RFI as well.··Is that correct? 20·· · ·A· ··Let me find that.··Yes, ma'am. 21·· · ·Q· ··Okay.··Now, one exhibit I passed out is Exhibit 22··No. 17, Mr. Morris.··And I'll represent to you even 23··though the total invoice -- subject to check, I'll 24··represent that this is an excerpted copy of an 25··exhibit -- of an invoice from Duggins Wren law firm KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 69 ·1··dated December 8th, 2011 that's included in State ·2··Agencies Exhibit No. 1 on a CD disc, and ask you to ·3··review it.··Does it look similar -- does it have ·4··components of some of the bills that you would have ·5··reviewed? ·6·· · ·A· ··It appears to, yes, ma'am. ·7·· · ·Q· ··Okay.··Now, is it possible -- we heard ·8··Mr. Considine agree that there were two meals in excess ·9··of $25 that weren't included on Exhibit No. 5 from a May 10··15th, 2012 invoice.··How about you?··Do you think in 11··addition to those there might be others that didn't make 12··the list? 13·· · ·A· ··What was that invoice that you referenced? 14·· · ·Q· ··Yeah, I didn't phrase the question very well. 15··I'll withdraw that question. 16·· · · · · · · ·Looking at State Agencies Exhibit No. 5, 17··did you have a hand in reviewing the meal receipts to 18··determine which meals should be disclosed on that chart 19··that's part of Exhibit No. 5? 20·· · ·A· ··Yes, ma'am. 21·· · ·Q· ··Okay.··So you would have reviewed those meal 22··invoices as part of your review in this case? 23·· · ·A· ··That's correct. 24·· · ·Q· ··Okay.··Now, if we look at Exhibit No. 17, can 25··we turn to Pages 18, 19, and 20?··And I'd like to have KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 70 ·1··you review those. ·2·· · · · · · · ·Now, if we look at 18, 19, and 20 and ·3··consult Exhibit No. 5 again, how many of these meal ·4··charges in excess of $25 are on the answer to Exhibit ·5··No. -- the answer to Staff's 9-9, which is Exhibit ·6··No. 5? ·7·· · ·A· ··(No audible response) ·8·· · ·Q· ··Well, in the interest of time, is it fair to ·9··say there's only one of these? 10·· · ·A· ··Which one? 11·· · ·Q· ··Look on Page 18.··Is the Royal House $60 charge 12··included in response to Staff's request for meals over 13··$25? 14·· · ·A· ··It is, yes. 15·· · ·Q· ··Now, looking on Page 19 and 20, are there other 16··meals that exceeded $25? 17·· · ·A· ··Yes. 18·· · ·Q· ··Okay.··Are those on State's Exhibit No. 5? 19··Were those disclosed in responses to Staff's request? 20·· · ·A· ··There is -- that's correct. 21·· · ·Q· ··Okay. 22·· · · · · · · ·MS. KELLEY:··I'd like to offer as a 23··demonstrative exhibit Exhibit No. 17, Your Honor. 24·· · · · · · · ·JUDGE BURKHALTER:··As a demonstrative? 25·· · · · · · · ·MS. KELLEY:··The complete invoice is KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 71 ·1··included in Exhibit No. 1, the CD that the State is ·2··offering. ·3·· · · · · · · ·JUDGE BURKHALTER:··Any objection to ·4··Exhibit No. 17? ·5·· · · · · · · ·MR. HOYT:··Not as a demonstrative. ·6·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. ·7·· · · · · · · ·(Exhibit State Agencies No. 17 admitted) ·8·· · ·Q· ··(BY MS. KELLEY)··Now, I had just a brief ·9··question about Gerald Tucker, the behind-the-scenes 10··consultant that was not a witness in this case. 11·· · ·A· ··He was a consulting expert. 12·· · ·Q· ··Okay.··You agree, don't you, that Mr. Tucker is 13··not and never has been an attorney? 14·· · ·A· ··I believe he's a certified public accountant. 15·· · ·Q· ··Well, is that status inactive, sir? 16·· · ·A· ··I don't know. 17·· · ·Q· ··Okay.··Well, just to refresh your recollection, 18··let me show you an RFI response that you sponsored in 19··response to State of Texas 3-5.··I'll ask you if you can 20··look that over. 21·· · ·A· ··Yes. 22·· · ·Q· ··Okay.··And can I ask you again, is Mr. Tucker's 23··CPA status inactive according to this response? 24·· · ·A· ··He has a CPA certificate.··He has an inactive 25··license. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 72 ·1·· · ·Q· ··Okay. ·2·· · · · · · · ·MS. KELLEY:··And I'm not offering this, ·3··Your Honor.··He's testifying about it. ·4·· · ·Q· ··(BY MS. KELLEY)··And finally, how long ago was ·5··the affiliates decision in Docket No. 16705 issued, the ·6··one we hear so much about as the reason why we need to ·7··document affiliates' costs? ·8·· · ·A· ··I believe that was in the early '90s.··I don't ·9··have an exact date. 10·· · ·Q· ··Okay.··Roughly two decades.··Correct? 11·· · ·A· ··That would be about right. 12·· · ·Q· ··Okay.··Isn't it logical by now that lessons 13··learned by a company and its law firm should have 14··included how to carry the burden of proof on affiliates' 15··cost after 20 years? 16·· · ·A· ··I disagree with your premise.··A company like 17··Entergy has, in this case, 19 affiliate witnesses. 18·· · · · · · · ·MS. KELLEY:··Well, Your Honor, I think it 19··was a "yes" or "no" question. 20·· · ·A· ··(BY MS. KELLEY)··Shouldn't the learning curve 21··by now have included -- 22·· · · · · · · ·JUDGE BURKHALTER:··You've got your answer. 23··He disagrees. 24·· · ·Q· ··(BY MS. KELLEY)··So you don't believe after 20 25··years that the Duggins Wren law firm or ETI and ESI KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 73 ·1··employees should know and understand how to ·2··document affiliates' costs? ·3·· · · · · · · ·MR. HOYT:··Objection; asked and answered. ·4·· · · · · · · ·JUDGE BURKHALTER:··Overruled. ·5·· · ·A· ··As I'm sure you know, the regulatory ·6··environment in Texas is an evolving area of law, and ·7··that, coupled with the fact that Entergy has a fairly ·8··complicated rate filing packet -- rate filing ·9··application that it has to make, being an integrated 10··utility, not a wires only company, that it, out of 11··necessity, needs to present the breadth and scope of the 12··case that it did. 13·· · ·Q· ··(BY MS. KELLEY)··So it's not reasonable we 14··should expect the Duggins Wren attorneys after two 15··decades to know and understand how to document an 16··affiliate's case? 17·· · ·A· ··It's not simply up to Duggins Wren.··It's the 18··Company -- I mean, the same people that provided 19··affiliate testimony in this underlying case were not the 20··same ones that -- or at least I guess for the most 21··part -- not the same ones that started providing 22··affiliate testimony two decades ago. 23·· · ·Q· ··Well, you said you guess.··You don't know 24··exactly how long some of these people that are providing 25··affiliates' testimony have been with the Company KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 74 ·1··exactly, do you? ·2·· · ·A· ··I don't have the exact time where each and ·3··every affiliate witness has testified in prior rate ·4··applications.··What I am saying is that over 20 years, ·5··you can expect that there would be personnel changes in ·6··areas where they would have responsibility for ·7··presenting their piece of that -- of the affiliate cost ·8··for a particular application.··You know, once -- once ·9··it's -- the fact that it may be figured out, so to 10··speak, in a particular case doesn't mean that it's then 11··cast in stone and that's all you do going forward.··You 12··know, there are lessons to be learned from every case. 13·· · ·Q· ··I understand.··But basically the case -- the 14··reason we've been given it, you'll agree, boils down to 15··Docket No. 16705.··Isn't that correct? 16·· · ·A· ··That was the case where Entergy -- 17·· · ·Q· ··Yeah, I understand.··I think the case speaks 18··for itself. 19·· · ·A· ··All right. 20·· · ·Q· ··What I'm asking is that has been the primary 21··reason identified by Entergy as justifying the need for 22··much of the rate case expense in this case.··Is that 23··correct? 24·· · ·A· ··It has certainly contributed to the rate case 25··expense. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 75 ·1·· · ·Q· ··Okay. ·2·· · ·A· ··Not only -- ·3·· · · · · · · ·MS. KELLEY:··I pass the witness. ·4·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you, ·5··Ms. Griffiths? ·6·· · · · · · · ·MS. GRIFFITHS:··No questions, Your Honor. ·7·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris? ·8·· · · · · · · ·MS. FERRIS:··Yes, Your Honor.··Thank you. ·9·· · · · · · · · · ··CROSS-EXAMINATION 10··BY MS. FERRIS: 11·· · ·Q· ··Good morning, Mr. Morris? 12·· · ·A· ··Good morning. 13·· · · · · · · ·MS. FERRIS:··First, Your Honor, we'd like 14··to exercise the right of optional completeness and offer 15··OPC Exhibit No. 3, which is based on Mr. Morris -- an 16··attachment to Mr. Morris' testimony that has a 17··transcript.··The transcript page cuts off the end of a 18··sentence, and we offer this to complete that discussion. 19··This page was not in there. 20·· · · · · · · ·JUDGE BURKHALTER:··Any objection? 21··Mr. Hoyt, any objection? 22·· · · · · · · ·MR. HOYT:··No, Your Honor. 23·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. 24·· · · · · · · ·(Exhibit OPUC No. 3 marked and admitted) 25·· · ·Q· ··(BY MS. FERRIS)··Mr. Morris, my questions for KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 76 ·1··you today are going to be limited to your rebuttal ·2··testimony.··Do you have that in front of you? ·3·· · ·A· ··I do. ·4·· · ·Q· ··What exhibit number is that again? ·5·· · ·A· ··ETI Exhibit 12. ·6·· · ·Q· ··Thank you.··I believe on Pages 6 and 7 of your ·7··rebuttal testimony -- and I'm referring to the 6 and 7 ·8··of 14. ·9·· · ·A· ··Okay. 10·· · ·Q· ··You have a Q and A in which you state that 11··Mr. Benedict recommends a disallowance based on the 12··Commission's rejection of ETI's purchased capacity 13··rider.··Is that a fair characterization of your 14··testimony there? 15·· · ·A· ··Yes. 16·· · ·Q· ··Are you aware that Mr. Benedict's testimony, 17··that his -- the lower bound -- the lower boundary of his 18··recommended disallowances only includes financial-based 19··incentive compensation and transmission equalization 20··costs and does not include this issue? 21·· · ·A· ··Do you have a copy of his testimony? 22·· · ·Q· ··Yes.··Let me -- Mr. Court Reporter, do you have 23··what's been marked as OPC Exhibit 1.··If not, I can 24··bring a copy. 25·· · · · · · · ·MS. FERRIS:··We anticipate offering this, KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 77 ·1··Your Honor, when Mr. Benedict is called. ·2·· · · · · · · ·JUDGE BURKHALTER:··Sure.··He's got a copy. ·3·· · ·A· ··I've got a copy. ·4·· · ·Q· ··(BY MS. FERRIS)··Okay.··Great.··Thank you. ·5··Mr. Morris, if you could turn in Mr. Benedict's ·6··testimony on Page 10.··I believe it's Page 10.··Yes. ·7··Page 10, Lines -- well, it begins at the very end of ·8··Line 13 with the word "as."··Line 13 through Line 22, it ·9··ends at the very beginning of Line 22.··Could you read 10··that passage, please? 11·· · ·A· ··"As described earlier" -- 12·· · · · · · · ·JUDGE BURKHALTER:··Do you want him to read 13··it to himself? 14·· · ·Q· ··(BY MS. FERRIS)··You can read it into the 15··record.··That's fine. 16·· · ·A· ··Let me just read it -- 17·· · ·Q· ··Well, read it to yourself.··That's fine. 18·· · ·A· ··Okay. 19·· · ·Q· ··Just let me know when you're done. 20·· · ·A· ··Okay.··I've read it. 21·· · ·Q· ··Okay.··So do you understand that the lower 22··bound of Mr. Benedict's recommendation did not 23··include -- only included the financial-based incentive 24··compensation and the transmission equalization costs? 25·· · ·A· ··That's what he says, yes. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 78 ·1·· · ·Q· ··Thank you.··And do you have any reason to ·2··dispute that? ·3·· · ·A· ··No. ·4·· · ·Q· ··Okay.··Thank you.··Then I'd like to turn to ·5··Page 5 of 14 of your rebuttal testimony.··And it does go ·6··over to Page 6 just a tad.··What I'm looking at is ·7··starting at Line 18 and continuing to the very first ·8··line of Page 6, you discuss the testimony of Cities' ·9··witness, Dennis Goins, and TIEC witness, Jeffry Pollock, 10··and state that they also recommended post test year 11··adjustments.··Is that correct? 12·· · ·A· ··Yes, ma'am. 13·· · ·Q· ··Do you understand that their recommendations 14··were both based upon test year costs, test year data? 15·· · ·A· ··I read it to mean that it involved a post test 16··year adjustment. 17·· · ·Q· ··But you don't know what the post test year 18··adjustment was calculated upon, do you? 19·· · ·A· ··No.··The point I was making was that they were 20··proposing a post test year adjustment from 1.84 to 21··4.1 million for Goins and adjustment to 2.7 million for 22··Pollock. 23·· · ·Q· ··Right.··But you -- 24·· · ·A· ··That was the point I was trying -- 25·· · ·Q· ··But you made no distinguishing -- you did not KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 79 ·1··make the distinction or did not consider what their post ·2··test year adjustment was based upon.··Is that right? ·3·· · · · · · · ·MR. HOYT:··Objection; vague.··I'm not sure ·4··what she means by what it's based upon.··I mean, he's ·5··saying he thinks they -- ·6·· · · · · · · ·JUDGE BURKHALTER:··I think it's pretty ·7··clear.··You can clarify it if you want to. ·8·· · · · · · · ·MS. FERRIS:··I thought it was very clear, ·9··Your Honor. 10·· · · · · · · ·JUDGE BURKHALTER:··Do you understand the 11··question? 12·· · ·A· ··I think so. 13·· · · · · · · ·JUDGE BURKHALTER:··Okay. 14·· · ·A· ··My point was that they were proposing post test 15··year adjustments. 16·· · ·Q· ··(BY MS. FERRIS)··Do you know if the Company's 17··post test year adjustment is based upon projected costs 18··after the test year? 19·· · ·A· ··Part of it, yes. 20·· · ·Q· ··Okay.··And even their alternate recommendation 21··was also based on data after the test year.··Is that 22··correct? 23·· · ·A· ··Yeah, part of it.··Yes.··Well -- 24·· · · · · · · ·MS. FERRIS:··I pass the witness. 25·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 80 ·1··Mr. Foley? ·2·· · · · · · · ·MR. FOLEY:··I have no questions. ·3·· · · · · · · ·JUDGE BURKHALTER:··Mr. Hoyt? ·4·· · · · · · · · · ·REDIRECT EXAMINATION ·5··BY MR. HOYT: ·6·· · ·Q· ··Just a couple of things, Mr. Morris.··Referring ·7··to the checklist Ms. Kelley asked you about, the rate ·8··case expense checklist, did you rely on the checklist in ·9··making the substantive determination as to whether 10··expenses were reasonable? 11·· · ·A· ··No.··That was my own adjustment and analysis. 12··The checklist was used primarily for a factual check, to 13··make sure that, you know, expenses and hours conformed 14··with the requirements in the agreements. 15·· · ·Q· ··And could you have performed that factual check 16··without the checklist? 17·· · ·A· ··Yes. 18·· · ·Q· ··Now I want to switch topics to -- you recall 19··Ms. Kelley asked you about affiliate -- the Company's 20··lessons learned about how to put on an affiliate case. 21··Correct? 22·· · ·A· ··Yes, sir. 23·· · ·Q· ··Okay.··And do you -- are you aware of whether 24··in 2002 the PUC issued additional guidelines related to 25··affiliate costs? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 81 ·1·· · ·A· ··I believe they did. ·2·· · ·Q· ··Okay.··And do you recall when Docket 16708 was? ·3·· · ·A· ··I believe that was in the early '90s, if I'm ·4··not mistaken.··I'm sorry.··I don't have the exact date. ·5·· · ·Q· ··Okay.··And since 16705, has the Company seen ·6··the disallowances to its affiliate costs that it ·7··received in that docket? ·8·· · ·A· ··No, not -- certainly not to that extent. ·9·· · ·Q· ··Okay. 10·· · · · · · · ·MR. HOYT:··That's all. 11·· · · · · · · ·JUDGE BURKHALTER:··Mr. Mack? 12·· · · · · · · ·MR. MACK:··No questions. 13·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley? 14·· · · · · · · ·MS. KELLEY:··No questions. 15·· · · · · · · ·MS. GRIFFITHS:··No questions. 16·· · · · · · · ·MS. FERRIS:··No questions, Your Honor. 17·· · · · · · · ·MR. FOLEY:··No questions. 18·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you. 19··Mr. Morris, you can step down. 20·· · · · · · · ·WITNESS MORRIS:··Thank you, sir. 21·· · · · · · · ·JUDGE BURKHALTER:··Let's go off the 22··record. 23·· · · · · · · ·(Recess from 11:34 a.m. to 11:40 a.m.) 24·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Let's go back on 25··the record.··Mr. Neinast, you rest, I gather? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 82 ·1·· · · · · · · ·MR. NEINAST:··Yes, Your Honor. ·2·· · · · · · · ·MS. KELLEY:··By way of housekeeping, I ·3··want to make sure that I offered all of my exhibits, ·4··Your Honor. ·5·· · · · · · · ·JUDGE BURKHALTER:··I just checked, and the ·6··answer is yes, you have, and I have them all. ·7·· · · · · · · ·MS. KELLEY:··Thank you. ·8·· · · · · · · ·JUDGE BURKHALTER:··Mr. Mack, we talked ·9··about your witnesses.··Do you want to offer Cities 10··Exhibits 1 and 2? 11·· · · · · · · ·MR. MACK:··We do. 12·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Any objections 13··to Cities Exhibits 1 and 2? 14·· · · · · · · ·MR. NEINAST:··No objection. 15·· · · · · · · ·JUDGE BURKHALTER:··They're admitted. 16·· · · · · · · ·(Exhibit Cities Nos. 1 and 2 admitted) 17·· · · · · · · ·JUDGE BURKHALTER:··And I gather you rest? 18·· · · · · · · ·MR. MACK:··We do. 19·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Let's see. 20··Ms. Kelley, I have got all your exhibits? 21·· · · · · · · ·MS. KELLEY:··Yes. 22·· · · · · · · ·JUDGE BURKHALTER:··All right. 23··Ms. Griffiths, do you have any exhibits you want to 24··offer? 25·· · · · · · · ·MS. GRIFFITHS:··No, Your Honor. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 83 ·1·· · · · · · · ·JUDGE BURKHALTER:··All right.··I think ·2··we're ready for you, Ms. Ferris. ·3·· · · · · · · ·MS. FERRIS:··Thank you.··The Office of ·4··Public Utility Counsel calls Mr. Benedict. ·5·· · · · · · · ·(Witness Benedict sworn) ·6·· · · · · · · ·JUDGE BURKHALTER:··Whenever you are ready. ·7·· · · · · · · ·MS. FERRIS:··Thank you. ·8·· · · · · · · ··PRESENTATION ON BEHALF OF ·9·· · · · · ·THE OFFICE OF PUBLIC UTILITY COUNSEL 10·· · · · · · · · · · ·NATHAN BENEDICT, 11··having been first duly sworn, testified as follows: 12·· · · · · · · · · ··DIRECT EXAMINATION 13··BY MS. FERRIS: 14·· · ·Q· ··Good morning, Mr. Benedict. 15·· · ·A· ··Good morning. 16·· · ·Q· ··Do you have before you what's been marked as 17··OPUC Exhibit No. 1? 18·· · ·A· ··I do. 19·· · ·Q· ··Can you identify this for the record, please? 20·· · ·A· ··It is my direct testimony and workpapers 21··submitted in this docket. 22·· · ·Q· ··Do you have any corrections to make? 23·· · ·A· ··I do.··I'd like to make a correction on Page 7. 24··And the correction is that Footnote 7, the text there 25··should be deleted. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 84 ·1·· · ·Q· ··Other than that correction, is the testimony ·2··before you -- if the questions were asked of you today, ·3··would your answers be the same? ·4·· · ·A· ··They would. ·5·· · · · · · · ·MS. FERRIS:··At this time, Your Honor, we ·6··offer OPUC Exhibit No. 1. ·7·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris, was that ·8··correction made in the court reporter's copies and the ·9··record copies? 10·· · · · · · · ·MS. FERRIS:··Yes, Your Honor, it was. 11·· · · · · · · ·JUDGE BURKHALTER:··All right.··Any 12··objection to OPUC Exhibit No. 1? 13·· · · · · · · ·MR. NEINAST:··With the elimination of 14··Footnote 7, ETI has no objection. 15·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. 16·· · · · · · · ·(Exhibit OPUC No. 1 admitted) 17·· · · · · · · ·MS. FERRIS:··We tender the witness. 18·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you. 19··Let me see here.··Mr. Mack? 20·· · · · · · · ·MR. MACK:··No questions. 21·· · · · · · · ·JUDGE BURKHALTER:··Ms. Kelley? 22·· · · · · · · ·MS. KELLEY:··No. 23·· · · · · · · ·JUDGE BURKHALTER:··Ms. Griffiths? 24·· · · · · · · ·MS. GRIFFITHS:··No. 25·· · · · · · · ·JUDGE BURKHALTER:··Mr. Foley? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 85 ·1·· · · · · · · ·MR. FOLEY:··Briefly. ·2·· · · · · · · ·JUDGE BURKHALTER:··Go ahead. ·3·· · · · · · · · · ··CROSS-EXAMINATION ·4··BY MR. FOLEY: ·5·· · ·Q· ··Mr. Benedict, could you turn to Page 10 of your ·6··testimony? ·7·· · ·A· ··Yes.··I'm there. ·8·· · ·Q· ··And at the bottom of the page, you refer to a ·9··$15.2 million quantification of three issues that, in 10··your opinion, were clearly -- that were litigated by 11··Entergy in the underlying rate case and were clearly 12··contrary to Commission precedent? 13·· · ·A· ··Well, it's two issues, to be correct. 14·· · ·Q· ··Okay.··And the two issues are what? 15·· · ·A· ··Incentive -- or financial-based incentive 16··compensation and transmission equalization costs. 17·· · ·Q· ··And the three -- okay.··And so could you 18··explain how you got to the quantification of 15.2 19··million? 20·· · ·A· ··Sure.··The transmission equalization cost, that 21··was the upward adjustment to MSS-2 proposed by the 22··Company, and that was a $9 million adjustment.··The 23··financial-based incentive compensation fees, I believe 24··the actual amount was at issue in the case, but 25··ultimately it was determined by the ALJs to be worth 6.2 KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 86 ·1··million.··And when you add the 9 million to 6.2 million, ·2··you get to the 15.2 million. ·3·· · · · · · · ·MR. FOLEY:··Thank you.··That's all I have. ·4·· · · · · · · ·JUDGE BURKHALTER:··Mr. Neinast? ·5·· · · · · · · ·MR. NEINAST:··No questions. ·6·· · · · · · · ·JUDGE BURKHALTER:··I have a question, ·7··Mr. Benedict. ·8·· · ·A· ··Yes. ·9·· · · · · · · · ··CLARIFYING EXAMINATION 10··BY JUDGE BURKHALTER: 11·· · ·Q· ··I think that the -- I'm not positive, but first 12··off, are you aware that there's a pending motion for 13··rehearing? 14·· · ·A· ··Yes. 15·· · ·Q· ··I think the MSS-2 and financial-based incentive 16··compensation issues might be among the issues that are 17··being argued in the pending motions for rehearing.··Are 18··you aware of that? 19·· · ·A· ··They very well could be. 20·· · ·Q· ··Okay.··Do you have an opinion on how the 21··outcome of this rate case expenses case could be 22··impacted by the outcome of those pending -- the 23··Commission's decision on those pending motions for 24··rehearing? 25·· · ·A· ··Those two items form a lower bound of my KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 87 ·1··recommendation, so that lower bound could move around ·2··based on that outcome.··But, otherwise, the rest of my ·3··testimony would be the same. ·4·· · ·Q· ··I didn't understand that.··As to -- let us ·5··hypothesize.··I don't know if it's likely or not, but if ·6··the Commission agrees with Entergy as to, say, ·7··financial-based incentive compensation -- whatever it's ·8··arguing in its motion for rehearing -- this may be ·9··hypothetical.··They may not be arguing about that issue. 10··But if they agreed with them and gave them what they 11··want on the motion for reconsideration, would that alter 12··your testimony? 13·· · ·A· ··It would change the amount of that lower bound 14··that I discussed in my testimony. 15·· · ·Q· ··In other words, are you saying you would then 16··believe they were entitled to reimbursement for that -- 17··for those expenses? 18·· · ·A· ··I think that's an accurate way to construe 19··that, yes. 20·· · · · · · · ·JUDGE BURKHALTER:··All right.··Thank you. 21··Ms. Ferris, in light of my questions, any redirect? 22·· · · · · · · ·MS. FERRIS:··I do have one, Your Honor. 23·· · · · · · · · · ·REDIRECT EXAMINATION 24··BY MS. FERRIS: 25·· · ·Q· ··Mr. Benedict, is it your understanding that the KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 88 ·1··motions for rehearing that are pending are on the order ·2··on rehearing?··Is that right? ·3·· · ·A· ··I don't know.··I presume that's true. ·4·· · · · · · · ·MS. FERRIS:··Okay.··I pass the witness. ·5·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Anybody? ·6·· · · · · · · ·(No response) ·7·· · · · · · · ·JUDGE BURKHALTER:··Mr. Neinast? ·8·· · · · · · · ·MR. NEINAST:··No, Your Honor. ·9·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Mr. Benedict, 10··thank you very much. 11·· · · · · · · ·WITNESS BENEDICT:··Great.··Thank you. 12·· · · · · · · ·JUDGE BURKHALTER:··Ms. Ferris, do you 13··rest? 14·· · · · · · · ·MS. FERRIS:··I rest, Your Honor. 15·· · · · · · · ·JUDGE BURKHALTER:··Do we have any other 16··witnesses? 17·· · · · · · · ·MR. FOLEY:··I do not. 18·· · · · · · · ·JUDGE BURKHALTER:··Does that mean we're 19··done? 20·· · · · · · · ·MR. FOLEY:··Has Staff's exhibit been 21··admitted, just for the record? 22·· · · · · · · ·JUDGE BURKHALTER:··No, sir. 23·· · · · · · · ·MR. FOLEY:··Okay.··I move to admit Staff's 24··Exhibit 1. 25·· · · · · · · ·JUDGE BURKHALTER:··1 and 2? KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 89 ·1·· · · · · · · ·MR. FOLEY:··No.··Just 1, actually.··2 is ·2··already in. ·3·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Any objection to ·4··Staff's Exhibit 1? ·5·· · · · · · · ·(No response) ·6·· · · · · · · ·JUDGE BURKHALTER:··It's admitted. ·7·· · · · · · · ·(Exhibit Commission Staff No. 1 admitted) ·8·· · · · · · · ·JUDGE BURKHALTER:··Any other evidence that ·9··needs to come in? 10·· · · · · · · ·(No response) 11·· · · · · · · ·JUDGE BURKHALTER:··Okay.··Are we ready for 12··closing argument?··I'm sorry.··Let's go off the record 13··and talk about briefing schedule. 14·· · · · · · · ·(Recess from 11:47 a.m. to 11:51 a.m.) 15·· · · · · · · ·JUDGE BURKHALTER:··We have agreed off the 16··record that we will have a briefing schedule whereby 17··initial briefs will be due on December 10th, 2012, and 18··replies will be due December 21st, 2012.··And I don't 19··think there's anything else we need to discuss, so with 20··that, we are adjourned.··Thank you all very much, and 21··have a happy holiday. 22·· · · · · · · ·(Proceedings concluded at 11:52 a.m.) 23·· 24·· 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 90 ·1·· · · · · · · · ··C E R T I F I C A T E · · ·2·· · · ·3··STATE OF TEXAS· ··) · · ·4··COUNTY OF TRAVIS··) · · ·5·· · · ·6·· · · · · ·I, Steven Stogel, Certified Shorthand Reporter · · ·7··in and for the State of Texas, do hereby certify that · · ·8··the above-mentioned matter occurred as hereinbefore set · · ·9··out. · · 10·· · · · · ·I FURTHER CERTIFY THAT the proceedings of such · · 11··were reported by me or under my supervision, later · · 12··reduced to typewritten form under my supervision and · · 13··control, and that the foregoing pages are a full, true · · 14··and correct transcription of the original notes. · · 15·· · · · · ·IN WITNESS WHEREOF, I have hereunto set my · · 16··hand and seal this 3rd day of December 2012. · · 17·· · · 18·· · · · · · · · · · · ··_________________________________ · · · · · · · · · · · · ··Steven Stogel 19·· · · · · · · · · · · ··Certified Shorthand Reporter · · · · · · · · · · · · ··CSR No. 6174 - Expires 12/31/2012 20·· · · · · · · · · · · · · ··Firm Certification No. 276 21·· · · · · · · · · · · ··Kennedy Reporting Service, Inc. · · · · · · · · · · · · ··1016 La Posada Drive, Suite 294 22·· · · · · · · · · · · ··Austin, Texas··78752 · · · · · · · · · · · · ··512.474.2233 23·· · · 24·· · · 25··Job No. 105605 KENNEDY REPORTING SERVICE, INC. 512.474.2233 ·1·· · · · · · · · · TRANSCRIPT OF PROCEEDINGS · · ·2·· · · · · · · · · · · ·· BEFORE THE · · ·3·· · · · · ·· PUBLIC UTILITY COMMISSION OF TEXAS · · ·4·· · · · · · · · · · · · AUSTIN, TEXAS · · ·5·· · · ·6·· · · ·7·· · · ·8·· · · ·9·· ·IN THE MATTER OF THE OPEN MEETING) · · 10··OF THURSDAY, APRIL 11, 2013· · ··) · · 11·· · · 12·· · · 13·· · · 14·· · · 15·· · · 16·· · · · · · BE IT REMEMBERED THAT AT approximately 9:35 · · 17··a.m., on Thursday, the 11th day of April 2013, the · · 18··above-entitled matter came on for hearing at the Public · · 19··Utility Commission of Texas, 1701 North Congress Avenue, · · 20··William B. Travis Building, Austin, Texas, · · 21··Commissioners' Hearing Room, before DONNA L. NELSON, · · 22··CHAIRMAN and KENNETH W. ANDERSON, JR., COMMISSIONER; and · · 23··the following proceedings were reported by Lou Ray, · · 24··Certified Shorthand Reporter. · · 25·· Page 2 ·1·· · · · · · · · · · ·TABLE OF CONTENTS · · ·2·· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE · · ·3··PROCEEDINGS, THURSDAY, APRIL 11, 2013 ..............· ·6 · · ·4·· · · · · · · · · ·COMMUNICATIONS AGENDA · · ·5·· · · · · · · · · · ·AGENDA ITEM NO. 1 · · ·6··DOCKET NO. 40582 - APPLICATION OF IMPERIO ·NETWORKS, LLC FOR A SERVICE PROVIDER · · ·7··CERTIFICATE OF OPERATING AUTHORITY ........... CONSENTED · · ·8·· · · · · · · · · · ·AGENDA ITEM NO. 2 · · ·9··DISCUSSION AND POSSIBLE ACTION REGARDING FCC ·ORDER ON RECONSIDERATION RELATING TO SUBMISSION · · 10··OF SERVICE AREA BOUNDARY DATA (WC DOCKET ·NO. 10-90 AND WC DOCKET NO. 05-337) .......... NOT HEARD · · 11·· · · 12·· · · · · · · · · · ·AGENDA ITEM NO. 3 · · 13··DISCUSSION AND POSSIBLE ACTION REGARDING ·IMPLEMENTATION OF STATE AND FEDERAL · · 14··LEGISLATION AFFECTING TELECOMMUNICATIONS ·MARKETS, CURRENT AND PROJECTED RULEMAKING · · 15··PROJECTS, AND COMMISSION PRIORITIES .......... NOT HEARD · · 16·· · · · · · · · · · ··ELECTRIC AGENDA · · 17·· · · · · · · · · · ·AGENDA ITEM NO. 4 · · 18··DOCKET NO. 40295; SOAH DOCKET NO. XXX-XX-XXXX - ·APPLICATION OF ENTERGY TEXAS, INC.··FOR RATE · · 19··CASE EXPENSES PERTAINING TO P.U.C. DOCKET ·NO. 39896 ..........................................· ·6 · · 20·· · · 21·· · · · · · · · · · ·AGENDA ITEM NO. 5 · · 22··PROJECT NO. 39246 - RULEMAKING PROCEEDING ·CONCERNING RECOVERY OF PURCHASED POWER · · 23··CAPACITY COSTS, INCLUDING AMENDMENT TO SUBST. R. ·25.238 .............................................··21 · · 24·· · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 3 ·1·· · · · · · · · · · ·TABLE OF CONTENTS · · ·2·· · · · · · · · · · · · · ·PAGE · · ·3·· · · · · · · · · · ·AGENDA ITEM NO. 6 · · ·4··PROJECT NO. 40979 - PROCEEDING TO TRACK ·COMPLIANCE WITH THE TERMS AND CONDITIONS · · ·5··SET FORTH IN THE COMMISSION'S ORDER ISSUED ·IN DOCKET NO. 40346 AND THE NUS, AND · · ·6··ASSOCIATED STUDIES ARISING FROM THE ORDER ·AND/OR NUS ................................... NOT · · HEARD ·7·· · · ·8·· · · · · · · · · · ·AGENDA ITEM NO. 7 · · ·9··PROJECT NO. 41060 - PROCEEDING TO EXAMINE ·THE INPUTS INCLUDED IN THE ERCOT CAPACITY, · · 10··DEMAND AND RESERVES REPORT ................... NOT HEARD · · 11·· · · · · · · · · · ·AGENDA ITEM NO. 8 · · 12··PROJECT NO. 41061 - RULEMAKING REGARDING DEMAND ·RESPONSE IN THE ELECTRIC RELIABILITY COUNCIL · · 13··OF TEXAS (ERCOT) MARKET ...................... NOT HEARD · · 14·· · · · · · · · · · ·AGENDA ITEM NO. 9 · · 15··PROJECT NO. 41210 - INFORMATION RELATED TO ·THE SOUTHWEST POWER POOL REGIONAL STATE · · 16··COMMITTEE .................................... NOT HEARD · · 17·· · · · · · · · · ··AGENDA ITEM NO. 10 · · 18··PROJECT NO. 41211 - INFORMATION RELATED TO ·THE ORGANIZATION OF MISO STATES .............. NOT · · HEARD 19·· · · 20·· · · · · · · · · ··AGENDA ITEM NO. 11 · · 21··PROJECT NO. 40000 - COMMISSION PROCEEDING TO ·ENSURE RESOURCE ADEQUACY IN TEXAS ............ NOT · · HEARD 22·· · · 23·· · · 24·· · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 4 ·1·· · · · · · · · · · ·TABLE OF CONTENTS · · ·2·· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE · · ·3·· · · · · · · · · ··AGENDA ITEM NO. 12 · · ·4··PROJECT NO. 37344 - INFORMATION RELATED TO ·THE ENTERGY REGIONAL STATE COMMITTEE ......... NOT HEARD · · ·5·· · · ·6·· · · · · · · · · ··AGENDA ITEM NO. 13 · · ·7··DISCUSSION AND POSSIBLE ACTION ON ELECTRIC ·RELIABILITY; ELECTRIC MARKET DEVELOPMENT; · · ·8··ERCOT OVERSIGHT; TRANSMISSION PLANNING, ·CONSTRUCTION, AND COST RECOVERY IN AREAS · · ·9··OUTSIDE OF ERCOT; SPP REGIONAL STATE ·COMMITTEE AND ELECTRIC RELIABILITY · · 10··STANDARDS AND ORGANIZATIONS ARISING UNDER ·FEDERAL LAW .................................. NOT HEARD · · 11·· · · 12·· · · · · · · · · ··AGENDA ITEM NO. 14 · · 13··DISCUSSION AND POSSIBLE ACTION REGARDING ·IMPLEMENTATION OF STATE AND FEDERAL · · 14··LEGISLATION, AFFECTING ELECTRICITY MARKETS, ·CURRENT AND PROJECTED RULEMAKING PROJECTS, · · 15··AND COMMISSION PRIORITIES ..........................··33 · · 16·· · · · · · · · · · ··GENERAL AGENDA · · 17·· · · · · · · · · ··AGENDA ITEM NO. 15 · · 18··DISCUSSION AND POSSIBLE ACTION REGARDING ·AGENCY REVIEW BY SUNSET ADVISORY COMMISSION, · · 19··OPERATING BUDGET, STRATEGIC PLAN, ·APPROPRIATIONS REQUEST, PROJECT ASSIGNMENTS, · · 20··CORRESPONDENCE, STAFF REPORTS, AGENCY ·ADMINISTRATIVE ISSUES, FISCAL MATTERS · · 21··AND PERSONNEL POLICY ......................... NOT HEARD · · 22·· · · 23·· · · 24·· · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 5 ·1·· · · · · · · · · · ·TABLE OF CONTENTS · · ·2·· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE · · ·3·· · · · · · · · · ··AGENDA ITEM NO. 16 · · ·4··DISCUSSION AND POSSIBLE ACTION REGARDING ·CUSTOMER SERVICE ISSUES, INCLUDING BUT · · ·5··NOT LIMITED TO CORRESPONDENCE AND ·COMPLAINT ISSUES ............................. NOT HEARD · · ·6·· · · ·7·· · · · · · · · · ··AGENDA ITEM NO. 17 · · ·8··DISCUSSION AND POSSIBLE ACTION ON ·INFRASTRUCTURE RELIABILITY, EMERGENCY · · ·9··MANAGEMENT; AND HOMELAND SECURITY ............ NOT HEARD · · 10·· · · · · · · · · ··AGENDA ITEM NO. 18 · · 11··ADJOURNMENT FOR CLOSED SESSION .....................··35 · · 12··RECONVENING OF OPEN MEETING ........................··36 · · 13··PROCEEDINGS CONCLUDED...............................··36 · · 14··REPORTER'S CERTIFICATE .............................··37 · · 15·· · · 16·· · · 17·· · · 18·· · · 19·· · · 20·· · · 21·· · · 22·· · · 23·· · · 24·· · · 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 6 ·1·· · · · · · · · · ·P R O C E E D I N G S · · ·2·· · · · · · · · ·THURSDAY, APRIL 11, 2013 · · ·3·· · · · · · · · · · · ··(9:35 a.m.) · · ·4·· · · · · · · ·CHAIRMAN NELSON:··Okay.··Let's go ahead · · ·5··and get started.··This meeting of the Public Utility · · ·6··Commission of Texas will come to order to consider · · ·7··matters that have been duly posted with the Secretary of · · ·8··State of Texas for today, April 11, 2013. · · ·9·· · · · · · · ·Stephen, I think we have a very short · · 10··consent agenda, but would you walk us through it? · · 11·· · · · · · · ·MR. JOURNEAY:··Yes, ma'am.··Good morning, · · 12··Commissioners.··By individual ballot the following item · · 13··was added to your consent agenda:··Item No. 1. · · 14·· · · · · · · ·CHAIRMAN NELSON:··The Chair will entertain · · 15··a motion to approve the consent agenda. · · 16·· · · · · · · ·COMM. ANDERSON:··You have the motion. · · 17·· · · · · · · ·CHAIRMAN NELSON:··Thank you.··Second. · · 18·· · · · · · · · · · ·AGENDA ITEM NO. 4 · · 19··DOCKET NO. 40295; SOAH DOCKET NO. XXX-XX-XXXX - ·APPLICATION OF ENTERGY TEXAS, INC.··FOR RATE · · 20··CASE EXPENSES PERTAINING TO P.U.C. DOCKET ·NO. 39896 · · 21·· · · 22·· · · · · · · ·CHAIRMAN NELSON:··Okay.··And No. 2 is not · · 23··taken up; 3 is not taken up, which brings us to Item 4. · · 24··Let me call up Docket No. 40295. · · 25·· · · · · · · ·So I generally agreed with the PFD on this KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 7 ·1··issue, but I would reverse on a few of the findings in ·2··the PFD.··So the first one I would -- I think not -- I ·3··think we were clear in a recent decision that we would ·4··not allow estimated rate expenses to be recovered in -- ·5··because they're estimated, and they could be recovered ·6··in the next docket when they're -- ·7·· · · · · · · ·COMM. ANDERSON:··Oh, you mean the -- ·8·· · · · · · · ·CHAIRMAN NELSON:··Yes, the Cities ·9··estimated -- I guess I should be clear, 4B the Cities 10··rate case expenses, I would -- I agree with the ALJ in 11··terms of everything except for the 75,800 that are 12··estimated. 13·· · · · · · · ·COMM. ANDERSON:··I agree.··And I agree 14··with you generally with just a couple of exceptions.··I 15··thought -- I agreed with the PFD. 16·· · · · · · · ·CHAIRMAN NELSON:··Right. 17·· · · · · · · ·COMM. ANDERSON:··I do think that one -- 18··that there's a finding of fact and conclusion of law 19··that will need to be added just to comply with the 20··requirements of 36.058. 21·· · · · · · · ·CHAIRMAN NELSON:··I agree, on affiliate 22··transactions. 23·· · · · · · · ·COMM. ANDERSON:··Yeah.··But we can get 24··back to that at the end. 25·· · · · · · · ·CHAIRMAN NELSON:··Okay.··And on C.2.a. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 8 ·1··which is financially based incentive compensation, I ·2··kind of struggled with this issue because I -- I ·3··understood what all the different parties were ·4··articulating, but ultimately I'm not sure in this docket ·5··it's appropriate for us to impose a new policy of ·6··disallowing rate case expenses related to advocacy of ·7··long-shot positions. ·8·· · · · · · · ·What I would like to do is, if it's okay ·9··with you, is open a rulemaking.··I think just the issue 10··in general of rate case expenses, whether it's a utility 11··or the cities, I think it's something that we've needed 12··to look at for a while, and this is the type of issue 13··that would be appropriate to include in that type of a 14··rulemaking. 15·· · · · · · · ·COMM. ANDERSON:··Well, I agree that we 16··ought to open up a rulemaking on it.··I -- with respect 17··to the PFD itself -- because interestingly in the four 18··and a half years I've been on the Commission, this is 19··actually the first contested case that is -- with 20··respect to -- 21·· · · · · · · ·CHAIRMAN NELSON:··Right. 22·· · · · · · · ·COMM. ANDERSON:··-- the expenses that's 23··actually has gotten to us.··On the issue of the PFD 24··itself, this is one where I spent a lot of time.··I 25··would actually adopt the PFD on the issue of the -- the KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 9 ·1··financial incentive compensation -- ·2·· · · · · · · ·CHAIRMAN NELSON:··Okay. ·3·· · · · · · · ·COMM. ANDERSON:··-- because I think that ·4··that was clearly -- whether you articulate it as a long ·5··shot or -- and you do raise, I think -- or you'll get to ·6··a point, if we end up going down this road in this ·7··particular case -- there's a question of a standard and ·8··then what the consequences are -- ·9·· · · · · · · ·CHAIRMAN NELSON:··Right. 10·· · · · · · · ·COMM. ANDERSON:··-- and that's a fair 11··point.··And that may dictate going back to just doing it 12··in a rulemaking.··But it was clear to me that all the 13··precedent we have excludes that kind of recovery.··And 14··so this was a -- it's almost charitable to call it a 15··long shot. 16·· · · · · · · ·CHAIRMAN NELSON:··Right. 17·· · · · · · · ·COMM. ANDERSON:··I know there was an 18··amicus brief that -- or amici brief that labeled that. 19··But the fact of the matter is that all the precedent is 20··against it.··We're not saying that a utility -- or the 21··judges aren't saying a utility can't raise the issue or 22··can't raise any issue.··They're simply saying that you 23··can't expect the ratepayers to bear it.··And so on this 24··issue I would actually adopt the PFD. 25·· · · · · · · ·However, on the next issue -- KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 10 ·1·· · · · · · · ·CHAIRMAN NELSON:··Okay. ·2·· · · · · · · ·COMM. ANDERSON:··-- where the judges ·3··struck down the -- let me get to it -- struck down the ·4··transmission -- you know, the future transmission ·5··expenses.··That one I actually would probably reverse ·6··the PFD because when I went back and actually looked ·7··at -- while the judges were absolutely correct that we ·8··ultimately -- that the judges recommended and that ·9··the -- this is the post test year transmission 10··equalization.··I understood what the judges were saying 11··in the -- in the PFD. 12·· · · · · · · ·However, I went back and actually looked 13··at the sections of the PFD in the Entergy rate case. 14··And while again they ultimately -- they ultimately found 15··that Entergy didn't meet its burden of proof, the 16··discussion in there was not, you know, as clear cut that 17··this was just a wild reach. 18·· · · · · · · ·CHAIRMAN NELSON:··Right. 19·· · · · · · · ·COMM. ANDERSON:··It was just that they 20··didn't meet their burden of proof, it wasn't known and 21··measurable.··And so on that particular issue I'd 22··actually cut Entergy some slack as opposed to 23··reversing -- I mean as opposed to adopting the PFD.··And 24··then I would -- and then adopt the PFD with respect to 25··the purchased power capacity rider. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 11 ·1·· · · · · · · ·So I don't feel -- this isn't a ·2··fall-on-my-sword thing, but that's sort of where I came ·3··down. ·4·· · · · · · · ·CHAIRMAN NELSON:··So what I'm hearing you ·5··say is when you look at the issue under C.2.a., which is ·6··the issue of financially based incentives compensation, ·7··what I'm hearing is almost like a -- in a civil court ·8··case where there's a frivolous -- a frivolous whatever ·9··it is.··You know, a Rule 13 under federal law, and I 10··don't know what it is under state law, but where you are 11··found to have filed a frivolous claim.··Actually, in 12··that case, I think you have to pay the attorneys' fees 13··of the other side.··But that is akin to the standard 14··that you're articulating for the financially based 15··incentive compensation. 16·· · · · · · · ·You're saying if there's a long line of 17··precedent and it doesn't -- and it's a decided issue at 18··the Commission, you can take your shot at trying to 19··overturn it.··But to the extent you lose, then you don't 20··get your attorneys' fees for that -- 21·· · · · · · · ·COMM. ANDERSON:··That's kind of where I 22··would come out, because it just seems -- and it's 23··particularly acute, I think, on the issue of the 24··financial incentive compensation because -- besides the 25··fact that there's long precedent for it, and consistent KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 12 ·1··precedent, it really does go to the benefit more of ·2··shareholders and investors than to ratepayers.··And, you ·3··know, at some point, utilities need to be -- exercise, ·4··you know, some prudence in their arguments.··So that's ·5··sort of where I come down, that it borders on frivolous. ·6·· · · · · · · ·But I wouldn't stop them from making the ·7··claim.··It's just they run the risk that if they do that ·8··it affects their recovery.··I just don't think it was a ·9··reasonable argument to make and then to ask ratepayers 10··to pay for it.··And that certainly would be my position 11··in the rulemaking. 12·· · · · · · · ·Now, to kind of close the loop on this, I 13··would adopt, then, the issue-specific reduction 14··approach, and -- 15·· · · · · · · ·CHAIRMAN NELSON:··Before we go there, can 16··I -- 17·· · · · · · · ·(Simultaneous discussion) 18·· · · · · · · ·CHAIRMAN NELSON:··Before we talk about how 19··we would address it, let me just say I do think it's -- 20··I agree with you.··I was going to say I don't disagree 21··with you, which is the same as agreeing with you. 22·· · · · · · · ·(Laughter) 23·· · · · · · · ·CHAIRMAN NELSON:··But I want to make sure, 24··as we move forward on this rulemaking, that we put the 25··same standard in place for all the parties so that -- KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 13 ·1··because I feel like -- I've always felt like we, as a ·2··Commission, could do a better job of scrubbing some of ·3··those numbers that are -- that the parties ask for in ·4··rate cases.··So to the extent that -- ·5·· · · · · · · ·COMM. ANDERSON:··I agree with you. ·6·· · · · · · · ·CHAIRMAN NELSON:· ·-- the Cities make an ·7··argument that's frivolous and they seek recovery of ·8··attorneys' fees on it, then they also wouldn't be ·9··entitled to get their attorneys' fees. 10·· · · · · · · ·So with that caveat, and the fact that 11··we're going to open a rulemaking on it, I'm okay with 12··moving forward where we -- I agree with you that the 13··financially based incentive compensation, while I would 14··have allowed recovery, I understand what you're saying 15··and I'm willing to go with you. 16·· · · · · · · ·On the transmission equalization expenses, 17··I agree with you on that as well and I think we should 18··allow those expenses. 19·· · · · · · · ·COMM. ANDERSON:··Yeah, I -- I wouldn't 20··reduce the -- 21·· · · · · · · ·CHAIRMAN NELSON:··Right. 22·· · · · · · · ·COMM. ANDERSON:··-- by some factor for 23··that. 24·· · · · · · · ·CHAIRMAN NELSON:··Right. 25·· · · · · · · ·COMM. ANDERSON:··And again, I actually KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 14 ·1··went back to the original PFD to sort of get a sense, ·2··because I think the judge -- and I give the judges a lot ·3··of deference in this.··They sat through the hearing, and ·4··one of them actually was a judge in the Entergy rate ·5··case.··But I -- the -- I thought they were a little ·6··overstrong in their argument about the transmission ·7··issue in light of going back and actually reading the ·8··original PFD on the issue. ·9·· · · · · · · ·CHAIRMAN NELSON:··Right. 10·· · · · · · · ·COMM. ANDERSON:··It just seemed like it 11··was -- maybe not a closer call, but less -- less clearly 12··settled and more fact based. 13·· · · · · · · ·CHAIRMAN NELSON:··Right.··And in terms of 14··the -- what we would disallow, I'm not really sure about 15··whether I'm comfortable with the issue-specific 16··reduction approach.··I guess I would ask staff if -- 17··would it be appropriate at this point to go back and 18··make sure we have in the record what we need from the 19··parties since we've made this decision now on -- if we 20··decided to pursue the issue and decrease it by the costs 21··attributable to that one specific issue, do we have 22··enough in the record to determine what that amount would 23··be? 24·· · · · · · · ·COMM. ANDERSON:··I mean, I -- it looks to 25··me like it would reduce the -- there would be a KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 15 ·1··disallowance of -- I mean, there would be an adjustment ·2··to rate base and removal of some O&M expenses.··I think ·3··the actual percentage then would drop from -- I think ·4··the judges recommended a 14 point -- was it 8 -- or some ·5··percentage it would be cut down to -- sort of ball park ·6··less than 7 percent, a haircut, maybe less.··Because I ·7··think the rate -- I think there would be a disallowance ·8··in rate base of about 335,000 and some change, maybe 336 ·9··rounded.··And then there's a disallowance of plant in 10··service. 11·· · · · · · · ·CHAIRMAN NELSON:··Well, rather than trying 12··to do this from the bench, would it be okay with you if 13··we ask all the parties who have participated to come 14··back to us with a number on what they think the 15··percentage should be? 16·· · · · · · · ·COMM. ANDERSON:··Okay.··That's fine. 17·· · · · · · · ·CHAIRMAN NELSON:··Or if -- because I see 18··staff is trying to figure out what the answer is as 19··well, our advising staff.··So that would be my 20··preference with that guidance. 21·· · · · · · · ·Stephen, is there a reason we can't bring 22··it back at the next Open Meeting after we get clarity on 23··that issue? 24·· · · · · · · ·MR. JOURNEAY:··No, ma'am, there's not. 25·· · · · · · · ·CHAIRMAN NELSON:··Okay. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 16 ·1·· · · · · · · ·MR. JOURNEAY:··I think -- there's ·2··certainly one number that the judge identifies in the ·3··PFD.··I think where there might be some uncertainty is ·4··dealing with the -- we also, in addition to disallowing ·5··incentive compensation, included an additional ·6··disallowance for the FICA that was associated with that. ·7··And while those numbers are clearly identifiable in the ·8··rate case docket in the ALJ number runs, I don't think ·9··that that particular number is specifically identified. 10·· · · · · · · ·CHAIRMAN NELSON:··Can you talk into your 11··mic? 12·· · · · · · · ·MR. JOURNEAY:··I'm sorry.··It's aggregated 13··in a number shown on a schedule in the Commission's 14··order, because there is a -- on our schedule for taxes 15··other than FIT -- line item for that.··But to break out 16··this particular number, we would have to go look at the 17··record in the -- in the rate case docket. 18·· · · · · · · ·CHAIRMAN NELSON:··Okay.··I think what 19··might be useful then is have the parties get together 20··and try to decide on -- try to come up with a number. 21··And if they can't agree to it, they can make filings and 22··y'all can review those.··Or would it be simpler just for 23··you to go back and come up with the numbers or have 24··staff making a filing? 25·· · · · · · · ·MR. JOURNEAY:··It might be appropriate for KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 17 ·1··the Commission to take notice of that part of the rate ·2··case docket record. ·3·· · · · · · · ·CHAIRMAN NELSON:··Okay. ·4·· · · · · · · ·MR. JOURNEAY:··The number runs, run by ·5··staff for the ALJs, because that's where we found the ·6··numbers. ·7·· · · · · · · ·CHAIRMAN NELSON:··Do we need additional ·8··runs?··That's my question. ·9·· · · · · · · ·MR. JOURNEAY:··We believe the numbers are 10··clearly identifiable on those schedules.··And then I 11··think if you -- to go where I think you want to go -- to 12··allow the parties to comment on those numbers. 13·· · · · · · · ·CHAIRMAN NELSON:··I don't want them to 14··comment.··I really want to understand what the number 15··is.··Because if we -- if we don't understand what it is 16··and we don't give them an opportunity to comment now, 17··we're going to get it on motion for rehearing.··So the 18··only thing I want to keep us from doing is making a 19··mistake on the numbers.··I'm not trying -- I'm not 20··giving them an opportunity to reargue the case. 21·· · · · · · · ·MR. JOURNEAY:··No, no, I was just -- to 22··point to the specific numbers -- 23·· · · · · · · ·CHAIRMAN NELSON:··Yes. 24·· · · · · · · ·MR. JOURNEAY:· ·-- that we think they are. 25··And I guess maybe we -- in the staff number runs for the KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 18 ·1··ALJs that were filed in that docket -- I know -- I don't ·2··have the front page on the data filing, but it's clearly ·3··identified in the AIS.··There is a Schedule 4 presented ·4··in Staff's number runs there, the taxes other than FIT. ·5··Under payroll taxes there's a line item for FICA that ·6··shows a Commission adjustment of $57,923. ·7·· · · · · · · ·Under "Other Taxes" there's an ESI payroll ·8··taxes line item that shows a Commission adjustment of ·9··121,549.··Because the incentive compensation was some 10··direct Entergy Texas employees and some Entergy Services 11··Incorporated allocated expenses to those employees, 12··there's a big chart in the -- dealing with how the 13··incentive compensation was broken out. 14·· · · · · · · ·CHAIRMAN NELSON:··Okay.··Ken, I have an 15··idea.··So let's have our advising staff to go back and 16··look at this number and come back to us.··In the 17··interim, if y'all feel like you need direction from the 18··parties, you can issue a memo asking for them to file 19··something.··Would that be okay with you, Ken? 20·· · · · · · · ·COMM. ANDERSON:··That's fine. 21·· · · · · · · ·MR. JOURNEAY:··Would you like us to file a 22··memo in this docket to identify these numbers and tell 23··them why we think -- 24·· · · · · · · ·COMM. ANDERSON:··I think that would be 25··helpful. KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 19 ·1·· · · · · · · ·CHAIRMAN NELSON:··Yes.··That would be ·2··useful. ·3·· · · · · · · ·COMM. ANDERSON:··And then the parties can ·4··comment -- ·5·· · · · · · · ·MR. JOURNEAY:··-- comment on whether they ·6··think we saw the right numbers or not. ·7·· · · · · · · ·CHAIRMAN NELSON:··That works.··That sounds ·8··great. ·9·· · · · · · · ·COMM. ANDERSON:··And by the way, just to 10··be clear, I think the judge got right the -- what the 11··denominator versus -- really what we're talking about is 12··coming up with the numerator on the formula. 13·· · · · · · · ·MR. JOURNEAY:··Correct. 14·· · · · · · · ·CHAIRMAN NELSON:··Right.··So I agreed with 15··the PFD on everything except for what we discussed.··So 16··I would uphold the PFD, but we'll do that at the next 17··meeting when you come back with those numbers. 18·· · · · · · · ·COMM. ANDERSON:··And I agree about opening 19··a rulemaking project to look at the issue of recovering 20··attorneys' fees broadly and set some criteria around it. 21·· · · · · · · ·MR. JOURNEAY:··We'll try and get this memo 22··out this afternoon.··I think we should be able to, or, 23··worst case, early tomorrow.··And then I would ask, I 24··guess, the parties to file a response by next Wednesday 25··so that we have it in time for your seven-day package KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 20 ·1··for the 25th Open Meeting. ·2·· · · · · · · ·CHAIRMAN NELSON:··That's fine.··Okay. ·3·· · · · · · · ·COMM. ANDERSON:··And then also let us know ·4··whether we need to reopen the record in some way to take ·5··judicial notice of the evidence in the rate case. ·6·· · · · · · · ·MR. JOURNEAY:··It might be appropriate for ·7··you to take notice of that today before we start running ·8··these -- shooting all these numbers out. ·9·· · · · · · · ·MS. FERRIS:··Your Honor, if I may, I 10··believe that the ALJ -- this is Sara Ferris with the 11··Office of Public Utility Counsel.··I believe that the 12··ALJs in the proceedings did take notice of the record in 13··the rate case.··That was so that the parties could brief 14··using the evidence in that record. 15·· · · · · · · ·CHAIRMAN NELSON:··Okay. 16·· · · · · · · ·COMM. ANDERSON:··Oh, okay.··Well, can you 17··just verify that?··And if we have to do it next Open 18··Meeting, we can. 19·· · · · · · · ·MR. JOURNEAY:··We will look for that and 20··then we'll go ahead and get this memo out then. 21·· · · · · · · ·CHAIRMAN NELSON:··Okay.··Thank you.··So 22··stay tuned. 23·· 24·· 25·· KENNEDY REPORTING SERVICE, INC. 512.474.2233 SOAR DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 40295 APPLICATION OF ENTERGY § BEFORE THE TEXAS, INC. FOR RATE CASE § PUBLIC UTILITY COMMISSION OF EXPENSES PERTAINING TO PUC § TEXAS DOCKET NO. 39896 § 1.: ,-,, ....., ,. = ......,, DIRECT TESTIMONY C'· ;z: 1 "'r, :·: ;:::: =:- ,.:: ~, = -c: ; <'"') I AND CJ~·· C• -· 0'1 ·«~- j r~ .-· , r~ ~ -0 4 :n .. 3'.: '• ·.· .: ·~ WORKPAPERS ·"" u -.. : ,,) c .r:- en ' OF NATHAN A. BENEDICT ON BEHALF OF THE OFFICE OF PUBLIC UTILITY COUNSEL November 6, 2012 OPUC Exhibit No. 1 SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 40295 DIRECT TESTIMONY AND WORKPAPERS OF NATHAN A. BENEDICT TABLE OF CONTENTS I. WITNESS IDENTIFICATION AND SCOPE OF TESTIMONY ............................... 3 III. ETl'S RATE CASE EXPENSES ..................................................................................... 5 APPENDIXA .............................................................................................................................. 12 WORK.PAPERS .......................................................................................................................... 16 Direct Testimony and Workpapers of Nathan A. Benedict On Behalf of the Office of Public Utility Counsel SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295 Page 2 of79 I I. WITNESS IDENTIFICATION AND SCOPE OF TESTIMONY 2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 3 A. My name is Nathan A. Benedict. My business address is 1701 North Congress Avenue, 4 Suite 9-180, Austin, Texas 7870 I. 5 Q. PLEASE STATE YOUR CURRENT EMPLOYMENT. 6 A. I am employed as Assistant Director of Regulatory Analysis for the Office of Public 7 Utility Counsel ("OPUC"). 8 Q. PLEASE STA TE YOUR EDUCATIONAL BACKGROUND. 9 A. I hold a Bachelor of Arts degree in Economics and German from the University of the 10 Pacific, a Master of Arts in Economics from California State University, East Bay, and a 11 Master of Science in Economics from The University of Texas at Austin. My graduate 12 studies included substantial training in statistics and econometrics as well as 13 specialization in the fields of public finance and industrial organization. A summary of 14 my educational background is included in Appendix A. 15 Q. PLEASE STATE YOUR PROFESSIONAL BACKGROUND. 16 A. I have over eleven years of experience in the utility industry. From 1998 to 2005, I 17 worked for Pac-West Telecomm, a Competitive Local Exchange Carrier ("CLEC"). I 18 held various management positions within Pac-West's operations group, including 19 management of the team responsible for provisioning Directory Assistance, E91 l, Local 20 Number Portability, and local loops in tandem with incumbent carriers in Pac-West's 21 service territory. From 2005 to 2006, I consulted for another CLEC, Telepacific, where I 22 designed voice and data networks for small- to medium-sized commercial customers. Direct Testimony and Workpapers of Nathan A. Benedict On Behalf of the Office of Public Utility Counsel SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295 Page 3 of79 I Since 2008, I have taught courses in microeconomics and macroeconomics as an adjunct 2 faculty member of Austin Community College. I began my tenure with OPUC in 2008. 3 A summary of my professional background is included in Appendix A. 4 Q. HAVE YOU PREVIOUSLY TESTIFIED REGARDING ELECTRIC UTILITY 5 MATTERS? 6 A. Yes. Appendix A includes a list of the cases in which I have testified. 7 Q. WHAT IS THE SUBJECT OF YOUR TESTIMONY? 8 A. My testimony addresses the amount of rate case expenses requested by Entergy Texas, 9 Inc. ("ETI" or "Company") 10 Q. PLEASE SUMMARIZE YOUR CONCLUSIONS. 11 A. 12 With respect to the overall amount of rate case expenses ETI is 13 allowed to recover, the expenses must be reasonable in order to be recovered, but the 14 Conunission is not required to grant recovery of every reasonable expense. Other 15 considerations, such as the frequency of rate cases, the overall amount of rate case 16 expenses in comparison to the granted rate increase, and the nature of the utility's rate 17 case request should be important components of the Conunission's review. Based on 18 these considerations, I recommend a reduction to ETI's request of between 14.5 and 73.6 19 percent. 1 1 This results in a recommended disallowance ranging from $1,269,123 to $6,441,896. Direct Testimony and Workpapers of Nathan A. Benedict On Behalf of the Office of Public Utility Counsel SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295 Page 4 of79 I n. - - - - -- -- - 2 Q. 3 4 A. 5 6 Q. 7 A. 8 9 10 11 12 13 14 15 - ID. ETl'S RATE CASE EXPENSES 16 Q. WHAT IS THE AMOUNT OF ETl'S REQUESTED RATE CASE EXPENSES? 17 A. ETI has requested recovery of $8,752,576 in rate case expenses related to Docket 18 No. 39896 and incurred through September 30, 2012. 4 2 Docket No. 39896, Schedule P-5 at 41-42. 3 Compliance Tariff ofAEP Texas Central Company Pursuant to Final Order in Docket No. 31433 Severed from Docket No. 28840, Docket No. 32385, Compliance Rider, Attachment Bat 3. 4 Supplemental Direct Testimony of Michael P. Considine, Exhibit MPC-SD-5 at 1 (October 25, 2012). Direct Testimony and Workpapers of Nathan A. Benedict On Behalf of the Office of Public Utility Counsel SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295 Page 5 of79 I Q. ARE THERE ANY OVERARCHING POLICY ISSUES THE COMMISSION 2 SHOULD CONSIDER WHEN REVIEWING RATE CASE EXPENSES? 3 A. Yes. Even when all of a utility's rate case expenses are deemed reasonable, the 4 Commission is not required to grant dollar-for-dollar recovery. PURA Sec. 36.06l(b)(l) 5 gives the Commission discretion in allowing recovery of rate case expenses, stating that 6 the regulatory authority "may allow'' as an expense the reasonable cost of participating in 7 the rate case. From a policy perspective, as the frequency of rate cases increases, it 8 becomes increasingly important to manage the cost of rate cases borne by ratepayers. 5 In 9 this docket, ETI's rate case expenses are substantial in comparison to the revenue 10 increase granted in Docket No. 39896, which is the Company's third base rate case in 11 little more than four years. Furthermore, the Company opted to litigate certain issues for 12 which Commission precedent is long-established and clear. The cost of challenging 13 Commission precedent on these issues forms part of the total rate case expenses ETI has 14 requested to recover from ratepayers. 15 Q. HOW DOES ETl'S RATE CASE EXPENSE REQUEST COMPARE TO THE 16 REVENUE INCREASE GRANTED IN THE RATE CASE AND TO ITS RATE 17 CASE EXPENSE IN PRIOR DOCKETS? 18 A. ETI's rate case resulted in a revenue increase of approximately $27.7 million on an 19 annual basis. 6 ETI's rate case expenses of approximately $8.75 million represent over 30 5 Aside from base rate cases, ET! can also update its EECRF and TCRF on an annual basis, and may soon have a PCRF mechanism available to it. 6 Docket No. 39896, ETl's Letter to Commissioners Regarding Corrections to Commission's Final Order in Docket No. 39896. Direct Testimony and Workpapers of Nathan A. Benedict On Behalf of the Office of Public Utility Counsel SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295 Page 6 of79 I percent of the actual revenue increase the Company was granted by the CommissioK 2 comparison, ETI's 2007 rate case, Docket No. 34800, resulted in a stipulated revenue 3 increase of $46.7 million and rate case expenses of $2.3 million per year for three years 4 to be recovered through a rider. 8•9 Docket No. 34800 involved two Hearings on the 5 Merits and myriad settlement negotiations. ETI's 2009 rate case, Docket No. 37744, 6 resulted in a stipulated revenue increase of $59 million effective August 5, 20 I 0 and an 7 additional increase of $9 million effective May 2, 2011. The revenue increase included 8 an unspecified amount for rate case expenses to be fully amortized in 20 I 0. 10 Thus, in 9 recent years, ETI' s ratepayers have borne the twin burdens of rate increases occurring 10 more frequently while also paying for the substantial litigation costs associated with the 11 rate increases. 12 Q. WERE SOME OF ETI'S RATE CASE EXPENSES INCURRED TO 13 CHALLENGE SETTLED PRECEDENT? 14 A. Yes. Part of the litigation costs in Docket No. 39896 relates to issues for which 15 Commission precedent is clear. As part of its statutory discretion, the Commission could 16 consider the degree to which ETI has overreached in its rate case when considering the 17 amount of litigation expenses allowed for recovery. I will provide a few examples to 18 illustrate this issue. 7 lJ:le $8.75 urlllion figure does not inelttd:e Cities' rate case e1cf1BHses efa13pr0ximately $1.2 miUioo,-9-- 8 The rider appeared on bills during 2009, 2010, and 2011. 9 Application ofEntergy Gui[ States, Inc.for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 34800, Order at 5, (Findings of Fact Nos. 24 and 27) (March 16, 2009). 0 ' Application ofEntergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744, Order at 5, (Findings of Fact Nos. 16 and 18) (December 13, 20 IO). Direct Testimony and Workpapers of Nathan A. Benedict On Behalf of the Office of Public Utility Counsel SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295 Page 7 of79 I ETI's rate filing package included a request to recover financial-based incentive 2 compensation. The ALJs note that all parties to the rate case, including ETI, agree that 3 Commission precedent allows recovery of only one type of incentive-based 4 compensation. While compensation tied to operational goals is recoverable, 5 compensation tied to financial goals is not. 11 ETI, nonetheless, requested recovery of all 6 incentive compensation costs, including those related to financial measures. Consistent 7 with its long-standing precedent, the Commission disallowed $6,196,037 in financially- 8 based incentive compensation. 12 9 A well-established criterion for the inclusion of an expense in rates is that the 10 expense be known and measurable. ETI requested an additional $9 million in 11 transmission equalization expense beyond the test year level. The Company's 12 transmission equalization expenses are affected by changes in transmission investment 13 made by the other Entergy Operating Companies. ETI estimated the transmission 14 projects to be completed by the other Operating Companies through the end of the rate 15 year to compute its adjustment. The ALJs found that because these projects are largely 16 not yet built, and may never be built, use of these projects to make an adjustment to test 17 year transmission equalization expense does not represent a known and measurable 18 change.13 In turn, the Commission denied ETI' s request to add $9 million to its 19 transmission equalization expense. 14 11 Docket No. 39896, Proposal for Decision at 166. 12 Docket No. 39896, Order at 24-25, (Findings ofFact Nos. 127-134) (September 14, 2012). 13 Docket No. 39896, Proposal for Decision at 116. 14 Docket No. 39896, Order at 20, (Findings ofFact Nos. 87 -94) (September 14, 2012). Direct Testimony and Workpapers of Nathan A. Benedict On Behalf of the Office of Public Utility Counsel SOAR Docket No. XXX-XX-XXXX; PUC Docket No. 40295 Page 8 of79 I Finally, instead of including purchased capacity costs in base rates, ETI requested 2 a purchased capacity rider in the rate case despite the fact that the Commission already 3 had a pending rulemaking to determine the structure of such a rider for all generating 4 utilities. Indeed, the Commission ultimately determined that the purchased capacity rider 5 requested by ETI should not be considered in the rate case due to the pending 6 rulemaking. 15 7 While the Commission has the authority to grant the utility recovery of costs 8 reasonably incurred in the litigation of its rate case, it is not required to do so. If there 9 were no room for discretion, the Legislature would not have used the word "may" when 10 giving the Commission the authority to grant recovery of rate case expenses. And 11 without the Commission having discretion, rate case expense proceedings would be mere 12 accounting exercises. A utility's request for recovery of rate case expenses should be 13 considered in the larger context. The frequency of rate cases, the amount of rate case 14 expenses relative to the size of the rate increase, and the type of relief requested by the 15 utility in its rate case should affect the outcome of the rate case expense docket. 16 Q. SHOULD ETI BE ALLOWED TO RECOVER THE FULL AMOUNT OF ITS 17 RATE CASE EXPENSES? 18 A. No. The policy considerations I have discussed warrant a reduction to ETI' s recoverable 19 rate case expenses. In addition, by exercising its discretion to limit rate case expenses, 20 the Commission can encourage settlement of rate cases. Settlement reduces the cost of 21 participation to all parties involved. Additionally, shifting a portion ofrate case expenses 15 Docket No. 39896, Supplemental Preliminary Order at 2 (January 19, 2012). Direct Testimony and Workpapers of Nathan A. Benedict On Behalf of the Office of Public Utility Counsel SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295 Page 9 of79 I from ratepayers to shareholders when challenging well-settled principles of ratemaking 2 will encourage a utility to carefully consider the degree to which it requests forms of 3 relief that run afoul of Commission precedent. 4 Q. HOW LARGE OF A REDUCTION TO RECOVERABLE RATE CASE 5 EXPENSES DO YOU RECOMMEND? 6 A. I suggest an upper and lower bound for any reduction the Commission decides to 7 implement. ETI was granted a rate increase of$27.7 million in Docket No. 39896, which 8 is $77.1 million less than the Company's request of $104.8 million. Because the 9 Commission reduced ETI's requested rate increase by approximately 73.6 percent, I 10 believe that it is reasonable to reduce ETI' s recoverable rate expenses by the same 11 percentage. This 73 .6 percent reduction forms the upper bound of my recommendation. 12 The lower bound of my recommendation is formulated by considering the 13 elements of ETl's base rate case that challenged clear Commission precedent. As 14 described earlier in my testimony, ETI requested recovery of financial-based incentive 15 compensation and a projected increase in transmission equalization costs, both of which 16 were denied by the Commission. The Company's request for recovery of financial-based 17 incentive compensation and the pursuit of a change to transmission expense that was 18 neither known nor measurable clearly contradict Commission precedent. It is not 19 reasonable for ratepayers to pay ETI's litigation expenses on these issues. Combined, 20 these issues contributed $15 .2 million to ETI' s requested rate increase of $104 .8 million, 21 and the disallowance associated with these issues reduced ETI's requested increase by 22 14.5 percent. Thus, a reasonable lower bound to the Commission's reduction to ETI's Direct Testimony and Workpapers ofNathan A. Benedict On Behalf of the Office of Public Utility Counsel SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295 Page 10of79 1 rate case expenses is 14.5 percent. Of course, this lower bound is based on the issues I 2 have identified and could be adjusted upward based on the testimonies and 3 recommendations of other parties to this docket. 4 Given my recommended band of 14.5 percent to 73.6 percent, it would be 5 reasonable to disallow between $1,269,123 and $6,441,896 of ETI's requested 6 $8,752,576 in rate case expenses. 7 Q. DOES TIDS CONCLUDE YOUR TESTIMONY? 8 A. At this time, yes. Direct Testimony and Workpapers of Nathan A. Benedict On Behalf of the Office of Public Utility Counsel SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 40295 Page 11 of79 APPENDIX A 12 EDUCATIONAL AND EMPLOYMENT HISTORY NATHAN A. BENEDICT EDUCATION M.S., Economics. Fields: Public Finance Industrial Organization The University of Texas at Austin, 2008 M.A., Economics. California State University, East Bay, 2005 B.A., Economics, German. University of the Pacific, 1999 EMPLOYMENT HISTORY Assistant Director, Regulatory Analysis Office ofPublic Utility Counsel State of Texas October 2008 - Present Adjunct Assistant Professor, Economics Austin Community College January 2008 - Present Teaching Assistant Introductory Economics The University of Texas at Austin August 2007 - May 2008 Research Assistant Human Investment Research and Education (HIRE) Center California State University, East Bay July 2005 - July 2006 Service Engineer US. Telepacific Corp. July 2005 - May 2006 13 Teaching Assistant Introductory Economics California State University, East Bay August 2005 - December 2005 Customer Relations Manager Senior Corporate Trainer Cross-Functional Assessment Manager Ordering and Provisioning Manager Pac-West Telecomm, Inc. April 1998 - March 2005 Testimony presented before the Texas Public Utility Commission: Subject No. 39896 Revenue Requirement; Cost Application of Entergy Texas, Inc. for Authority to Allocation; Rate Design Change Rates and Reconcile Fuel Costs No. 39366 Application of Entergy Texas, Inc. for Authority to Allocation of Energy Efficiency Redetermine Rates for the Energy Efficiency Cost Performance Bonus Recovery Factor Tari.ff and Request to Establish a Revised Energy Efficiency Goal and Cost Caps No. 38306 Texas-New Mexico Power Company's Request for AMS Communications Network; Approval of Advance Metering System (AMS) Discretionary Service Charges; Low- Deployment and AMS Surcharge Income Programs No. 37744 Product Solicitation Process; Product Application of Entergy Texas, Inc. for Authority to Pricing; Miscellaneous Electric Change Rates and Reconcile Fuel Costs Service Charges; Rate Riders No. 37482 Product Solicitation Process and Application of Entergy Texas, Inc. for Approval of a Product Pricing Power Cost Recovery Factor No. 36952 Application of CenterPoint Energy Houston Electric, Computation of Energy Efficiency LLC to Defer Energy Efficiency Cost Recovery and Performance Bonus for Approval of an Energy Efficiency Cost Recovery Factor 14 No. 36851 Application of the Electric Reliability Council of Project Funding Sources and Texas, Inc. for Approval of a Revised Nodal Market Surcharge Allocation Implementation Surcharge No. 36025 Revenue Requirement; Cost Application of Texas-New Mexico Power Company Allocation; Rate Design for Authority to Change Rates 15 WORKPAPERS 16 , PROCEEDING TO CONSIDER RATE § CASE EXPENSES SEVERED FROM § DOCKET NO. 28840 (APPLICATION OF § AEPTEXASCENTRALCOMPANYFOR § AUTHORITY TO CHANGE RATES) § § ORDER 'This Order addresses the recoverable rate-case expenses.of AEP Texas Central Company (AEP Central) and of Cities1 in connection with their participation in Docket No. 28840.2 As set forth in this Order, the Public Utility Commission of Texas (Commission) determines that AEP Central's recoverable rate case expenses through June 2005 are $2,938,130 and that Cities' recoverable rate case expenses are $1,350,149. As discussed herein, the Cities' expenses relating to witness Sarah Goodfriend have been reduced by one-half as recommended by the State Office of Administrative Hearings (SOAR) Administrative Law Judges in their Proposal for Decision (PFD) in Docket No. 28840.3 'This Order finds that $4,288,429 in rate-case expenses incurred by AEP Central and Cities is reasonable and necessary and authorizes AEP Central to implement a surcharge over three years to recover this amount. I. Procedural History On November 3, 2003, AEP Central filed an application seeking a change in its rates. 'This application was assigned Docket No. 28840, and the Commission referred the case to SOAH on November 4, 2003. SOAH issued its initial PFD in Docket No. 28840 on July 1, 2004, which contained certain findings on rate case expenses. In July and August-2004, the Commission issued two orders on remand in Docket No 28840 directing SOAH to consider further and provide further evaluation of certain specified issues, none of which involved rate case expenses. On November 1 Alice, Aransas Pass, Carrizo Springs, Dilley, Donna, Eagle Lake, Freer, Ganado, George West, Ingleside, Kingsville, LaFeria, Laguna Vista, La Joya, Leakey, Los Fresnos, Lyford, Lytle, McAllen, Mercedes, Mission, Nordheim, Odem, Pharr, Port Aransas, Portland, Port Lavaca, Poteet, Rancho Viejo, Refugio, Rio Hondo, Rwige, San Benito, San Juan, Sinton, Uvalde, and Weslaco (collectively, Cities). 2 Application of AEP Texas Central Company for Authority to Change Rates. Docket No. 28840, Order (Aug. IS, 2005). 3 Docket No. 28840, Proposal for Decision at 121-127, 205 (FOF 210-216), 209 (FOF 256)(Jul. I, 2004). 3:1- 17 DOCKET NO. 31433 ORDER PAGE2 ' 16, 2004, SOAH issued its Remand PFD. In addition, the Commission held hearings on certain matters relating to merger savings and affiliated expenses on March 3, 4, and 7. The Commission issued its final order in Docket No. 28840 on August 15, 2005. In that order, the Commission severed the determination of the reasonableness and necessity of rate case expenses to this proceeding, Docket No. 31433.4 While rate-case expenses were not addressed on the remand SOAH hearing and the Commission-held hearing, Cities and AEP incurred additional expenses as a result of these hearings, and submitted updated information on these additional expenses. Based on the submission, the Commission decided to sever the determination on rate-case expenses to examine this additional evidence. 5 By Order No. 1 in this proceeding, AEP Central and Cities were directed to file detailed supporting documentation of their requested rate case expenses. On September 9, 2005, AEP Central and Cities filed such supporting documentation. On September 16 and October 10, 2005, AEP Central made supplemental filings that furnished additional supporting documentation with respect to certain of its requested expenses. On October 14, 2005, the parties filed statements of position and on October 28, 2005, AEP Central filed its Motion for Ruling on Disputed Issue and Conditional Request for a Hearing. On December 12, 2005, the presiding officer issued Order No. 4, which requested clarification regarding contested issues. On December 22, 2005, the parties filed responses to Order No. 4. The parties' filings established that there are no contested factual issues in Docket No. 31433 that have not been fully litigated in Docket No. 28840. To the extent AEP Central had previously conditionally requested a hearing, that request was withdrawn by AEP Central's December 22, 2005 filing. The sole disputed issue is the recoverability of one-half of Cities' witness · Sarah Goodfriend' s expenses, which the SOAH ALJs had recommended be disallowed in their PFD in Docket No. 28840 issued on July 1, 2004. Since there are no contested factual issues that have not already been fully litigated, an evidentiary hearing on the merits is not necessary or appropriate. The disposition of the sole contested issue is discussed in the subsequent" section of this Order. 'Docket No. 28840, Order at 60 (Ordering, S) (Aug. IS, 2005). ' Open Meeting Tr. at 54-62 (July 29, 2005). 18 DOCKET NO. 31433 ORDER PAGE3 II. Recoverability of One-Half of Dr. Goodfriend's Expenses In Docket No. 28840, AEP Central submitted testimony challenging the quality of a survey that fonned the basis of testimony submitted by Cities witness, Dr. Sarah Goodfriend. 6 Following a full evidentiary hearing and briefing on this and other issues, the SOAH ALJs recommended that one-half of Dr. Goodfriend's expenses be disallowed because they found that the methodology of the survey she conducted was "seriously flawed." 7 In severing the issue of rate case expenses from Docket No. 28840 to this proceeding, the Commission intended that the entire evidentiary record in Docket No. 28840 on rate case expenses as well as the Commission's initial decisions be carried over to this case. Thus, the evidentiary record on the quality of Dr. Goodfriend' s work underlying her testimony in Docket No. 28840 and the SOAH ALJs' findings regarding the recoverability of one-half of her expenses are before the Commission for decision in this proceeding. The purpose of the severance, however, was to evaluate the detailed supporting documentation on updated rate-case expenses submitted by AEP Central and Cities.8 This proceeding was not initiated as a forum for Cities to re-litigate Dr. Goodfriend's expenses. The Commission had previously found that the ALJs correctly determined that one-half of Dr. Goodfriend's expenses should be disallowed9 because the survey she conducted ''was seriously flawed and that conclusions drawn from the data cannot be reasonably supported under current legal standards." 10 The Commission reaffinnS this determination, and therefore, the Commission adopts the SOAH ALJs' finding that one-half of Dr. Goodfriend's expenses should be disallowed. In addition, as there are no other outstanding contested issues related to the rate-case expense information submitted in Docket No. 28840 or the additional rate-case expense infonnation 6 See Docket No. 28840, Proposal for Decisioo at 121-127, 205 (FOF 212) (Jul. I, 2004). 7 Id at 125. 1 See Open Meeting Tr. at 62 (Jul. 29, 2005). 9 Open Meeting Tr. at 196-198 (January 13, 2005). 10 Docket No. 28840, Proposal for Decision at 125 (Jul. I, 2004). 19 DOCKET NO. 31433 ORDER PAGE4 submitted in this docket, the Commission finds that the rate-case expenses of $2,938,130 for AEP Central and $1,350,299 for Cities are reasonable and necessary. III. The SOAH AL.ls' Findings and Conclusions in Docket No. 28840 In the PFD issued on July 1, 2004, in Docket No. 28840, the SOAH ALJs included Finding of Fact Nos. 210 through 216 and Conclusion of Law No. 58 addressing rate case expenses. The SOAH ALJs' findings were issued prior t-0 the updating by AEP Central and Cities of their rate case expenses in their filings described in Finding of Fact No. 15. Thus, in order to reflect the updated factual evidence filed in Docket No. 31433 and certain other corrections described below, the Commission modifies the SOAH ALJs' Finding of Fact Nos. 210 through 216 as follows. Finding of Fact Nos. 22 through 25 of this Order modify the SOAH ALJs' Finding of Fact No. 210 to reflect the updated amounts of rate case expenses found reasonable and necessary for AEP Central after reflecting the disallowance recommended by Staff; Finding of Fact No. 27 of this Order modifies the SOAH ALJs' Finding of Fact No. 211 to reflect the updated amount of Cities' requested rate case expenses. Finding of Fact Nos. 28 and 29 of this Order modify the SOAH ALJs' Finding of Fact No. 212 to reflect the updating of Dr. Goodfriend's portion of Cities' requested rate case expenses. Finding of Fact Nos. 31 and 32 of this Order adopt the SOAH ALJs' Finding of Fact Nos. 214 and 215. Finding of Fact No. 33 of this Order modifies the SOAH ALJs' Finding of Fact No. 216 to reflect the amounts found reasonable and necessary by the Commission based on the updated information in this proceeding and corrects it to reflect that the rate case expenses will be collected through a three-year surcharge and not through cost of service. Finding of Fact No. 34 of this Order supplements the SOAH ALJs' Finding of Fact No. 256 to reflect the updated amounts for AEP Central's and Cities' rate case expenses found reasonable and necessary by this Order. Finding of Fact No. 35 reflects the Commission's policy decision, in accordance with its decision in Docket No. 30706,11 that AEP Central not be permitted to recover estimated appeal costs in this proceeding, but that AEP Central be afforded the opportunity to recover in its next rate case any reasonable and necessary expenses for Docket Nos. 28840 and 31433 that it 11 Application of CenterPoinJ Energy Houston Electric, UC for a Competition Transition Charge, Docket No. 30706, Order at 28-29, 47 (COL 28) (Jul. 14, 2005). 20 DOCKET NO. 31433 ORDER PAGES subsequently incurs that exceed the amounts found reasonable and necessary by this Order. Finally, Conclusion of Law No. 6 in this Order incorporates the SOAH ALJs' Conclusion of Law No. 58. The Commission adopts the following findings of fact and conclusions oflaw: IV. Findings of Fact A. Background and Procedural Matters 1. AEP. Central is an electric utility providing transmission and distribution (T&D) services in a 44,000 square·mile area of South Texas that includes the portion of Texas from just south of San Antonio to the Mexican border and from Bay City west to Eagle Pass. AEP Central's service area is located within the Electric Reliability Council of Texas (ERCOT). 2. On November 3, 2003, AEP Central filed an application with the Commission to change its T&D rates. The Commission assigned AEP Central' s application to Docket No. 28840. 3. Concurrent with filing its application with the Commission, AEP Central filed a similar petition and statement of intent with each incorporated city in its certificated service area that retains jurisdiction over its retail rates. Eighty-six (86) cities denied AEP Central's petition and statement of intent. AEP Central filed petitions for review of those denials and filed motions to consolidate those petitions for review into Docket No. 28840. 4. On November 4, 2003, the Commission referred AEP Central's application in Docket No. 28840 to SOAH to conduct an evidentiary hearing on the merits and issue a PFD. 5. The following parties intervened and participated in the hearing in Docket No. 28840: Cities; Texas Industrial Energy Consumers (TIEC); CPL Retail Energy (CPL Retail); Coalition of Commercial Ratepayers (CCR); City of Garland, Alliance for Retail Markets (ARM); TXU Business Services (TXU); Texas Legal Services Center and Texas Ratepayers' Organization to Save Energy (TLSCROSE); South Texas Electric Cooperative, Inc. (STEC); State of Texas; Office of Public Utility Counsel (OPC); and Commission Staff (Staff). 21 DOCKET NO. 31433 ORDER PAGE6 6. In Docket No. 28840, AEP Central requested approval of a revenue requirement of $519.9 million, based on an historical test year of July 1, 2002, through June 30, 2003. Of that amount, $426.6 million was for providing retail T&D service (including the portion of the ERCOT -wide transmission costs) and $93.3 million for providing wholesale transmission service. 7. The evidentiary hearing on the merits in Docket No. 28840 was held on March 2 through March 18, 2004. 8. On July 1, 2004, the SOAH ALJs assigned to hear Docket No. 28840 issued their PFD. The PFD contained certain findings with respect to rate case expenses. 9. The Commission issued orders on July 28 and August 25, 2004, remanding portions of Docket No. 28840 to SOAH, none of which involved rate case expenses. 10. On November 16, 2004, the SOAH ALJs issued their Remand PFD in Docket No; 28840. 11. On March 3, 4, and 7, 2005, the Commission held hearings on merger savings and affiliate expenses. 12. On August 15, 2005, the Commission issued its final order in Docket No. 28840. In Ordering Paragraph 5 of that order, the Commission severed the determination of the reasonableness and necessity of rate case expenses into this proceeding, Docket No. 31433. All portions of the evidentiary record in Docket No. 28840 relevant to rate case expenses are part of the evidentiary record in this Docket No. 31433. 13. On August 26, 2005, the presiding officer issued Order No. 1, which required the parties to file evidence of rate case expenses and directed AEP Central and Cities to file supporting " detailed documentation for their requested rate case expenses. Order No. 1 also made all parties to Docket No. 28840 parties to this proceeding. 22 DOCKET NO. 31433 ORDER PAGE7 14. On August 29, 2005, Cities requested clarification from the presiding officer regarding the extent of the supporting documentation the Cities were required to submit under Order No. I. 15. On August 30, 2005, Order No. 2: Clarification of Order No. 1, was issued informing Cities that: The entirety of the rate case expenses will be considered in this proceeding. To the extent supporting documentation for expenses prior to September 2004 is in the record of Docket No. 28840, Cities may simply provide the relevant cite to the record. If the supporting documentation for expenses is not in the Docket No. 28840 record, that information should be submitted in this proceeding. 16. On September 9, 2005, AEP Central and Cities filed supporting documentation for their requested rate case expenses, consisting of invoices, timesheets, receipts, etc. On September 16 and October 10, 2005, AEP Central filed supplemental information related to certain of its requested rate case expenses. 17. On September 19, 2005, the presiding officer established a procedural schedule for this docket. In accordance with the procedural schedule, statements of position were due on October 14, 2005, and requests for hearing were due on October 28, 2005. 18. On October 14, 2005, AEP Central, Cities, and Staff filed statements of position. In its statement of position, Staff questioned certain items of AEP Central' s rate case expenses as lacking adequate supporting documentation. in its statement of position, AEP Central stated that the SOAH ALJs had recommended that one~half of Dr. Goodfriend's expenses be disallowed and noted that Cities' requested rate case expenses included the entire amount billed by Dr. Goodfriend to Cities, and not one-half of that amount. In its statement of position, Cities indicated that they did not contest any of AEP Central' s rate case expenses, but indicated that if Cities' request associated with Dr. Goodfriend' s work was contested, then Cities would urge that the standard applied to Dr. Goodfriend be applied to AEP Central' s experts. 23 DOCKET NO. 31433 ORDER PAGES 19. On October 28, 2005, AEP Central filed a motion for ruling on a disputed issue and conditionally requested a hearing seeking a Commission ruling on whether, by severing rate case expenses from Docket No. 28840, it intended to reopen for litigation the issue of Dr. Goodfriend' s expenses which had been fully litigated in Docket No. 28840. AEP Central 's pleading also included an identification of the portions of the record in Docket No. 28840 that addressed the issue of the quality of Dr. Gooclfriend's work and the recovery of her rate case expenses. 20. On December 12, 2005, the presiding officer issued Order No. 4, which requested a clarification regarding a contested issue and directed Staff to file a list of disputed factual . issues and a list of threshold legal and policy issues that must be addressed before this proceeding can be resolved, and permitting AEP Central and Cities to make similar filings. 21. On December 22, 2005, AEP Central and Cities filed their responses to Order No. 4. In its response, AEP Central withdrew its conditional request for a hearing. 22. Based on the filings of the parties set forth in Finding of Fact Nos. 16, 18, 19, and 21, the Commission finds that no factual matters that have not already been fully litigated in Docket No. 28840 are at issue or disputed. The only disputed issue in this proceeding involves the recoverability of one-half of Cities' witness Gooclfriend's expenses, which has been subjected to a full contested case evidentiary hearing, briefing, and the issuance by the SOAH ALJs of a PFD in Docket No. 28840. B. AEP Central's Rate Case Emenses 23. Based on its filing of September 9, 2005, as supplemented by its filings of September 16 and October 10, 2005, AEP Central sought recovery of $2,962, 734 in recoverable rate case expenses for Docket No. 28840 through June 2005. 24. In its statement of position filed on October 14, 2005, Staff ·questioned whether $24,604 of AEP Central's requested rate case expenses were supported by adequate underlying documentation and recommended disallowance of these expenses. 24 DOCKET NO. 31433 ORDER PAGE9 25. In its filing of October 28, 2005, AEP Central indicated that it did not contest Staff's recommendation to disallow $24,604 of AEP Central's requested rate case expenses. 26. AEP Central's reasonable and necessary rate case expenses for Docket No. 28840 as of June 2005 are $2,938,130. C. Cities' Rate Case Emenses 27. In its filing of September 9, 2005, Cities requested rate case expenses for Docket No. 28840 of $1,391,925. This amount consisted of $1,166,925 in expenses actually incurred through July 2005 and $225,000 in estintated expenses including appeals. 28. Cities' actual expenses of $1,166,925 through July 2005 included $83,253 billed by Cities' witness Sarah Goodfriend. 29. The Commission adopts the SOAH ALJs' finding regarding disallowance of one-half of Dr. Goodfriend' s expenses from Docket No. 28840 because of the inadequacies in the survey she performed. The record indicates that Dr. Goodfriend has billed the Cities $83,253; therefore a disallowance of one-half of her fees is $41,626. 30. Based on Findings of Fact Nos. 27 through 29, Cities' recoverable rate case expenses are $1,350,299. 31. AEP Central 's proposal to disallow Cities' witness Starnes expenses is not appropriate because the principal rate design issues raised by Cities benefit other rate payers. 32. Cities' rate case expenses are system costs that should be home by all ratepayers because other ratepayers benefit from the Cities' participation. D. Rate Case Expense Surcharge 33. Based on Finding of Fact Nos. 26 and 30, the aggregate amount of rate case expenses found reasonable and necessary for AEP Central and Cities are $4,288,429. 25 DOCKET NO. 31433 ORDER PAGE IO 34. It is appropriate for AEP Central to surcharge the aggregate rate case expenses found reasonable and necessary in Finding of Fact No. 33 to be collected from all customers over three years. E. Subsequent Rate Case Expenses 35. To the extent AEP Central incurs rate case expenses foi: Docket Nos. 28840 and 31433 after June 2005, it is reasonable for it to recover such expenses in its next rate clise to the extent it demonstrates that such additional expenses are reasonable and necessary. Also, to the extent that Cities incur rate case expenses for Docket Nos. 28840 and 31433 after July 2005 that cause Cities' aggregate rate case expenses to exceed the amount found recoverable by this Order, it is reasonable for AEP Central to recover such expenses in its next rate case to the extent found reasonable and necessary. V. Conclusions of Law 1. AEP Central is an electric utility as defined by §§ 31.002 of the Public Utility Regulatory Act, TEX. UTIL. CODE.ANN.§§ 11.001-66.017 (Vernon 1998 & Supp. 2005) (PURA) and is therefore subject to the Commission's jurisdiction under PURA §§ 32.001, 33.051, and 36.102. 2. AEP Central is a T&D utility as defined in PURA § 31.002(19). 3. SOAH had jurisdiction over all matters relating to the conduct of the hearing in Docket No. 28840, including the preparation ofa Proposal for Decision pursuant to PURA§ 14.053 and TEX. Gov'T CODE ANN.§ 2003.049(b). 4. AEP Central met its burden of proof regarding the amount of its rate case expenses for Docket No. 28840 through June 2005 found reasonable and necessary in Finding of Fact No. 26. 26 DOCKET NO. 31433 ORDER PAGEll 5. With the exception of the Cities' rate case expenses disallowed in Finding of Fact No. 29, Cities met their burden of proof that their rate case expenses for Docket No. 28840 are reasonable and necessary. 6. Cities are entitled to reimbursement for their rate case expenses as customers, as well as for being regulatory authorities. 7. The evidentiary record in Docket No. 28840 on rate case expenses, including the portion related to the quality of work performed by Dr. Goodfriend underlying her testimony submitted in Docket No. 28840 identified in AEP Central's pleading described in Finding of Fact No. 19, is part of the evidentiary record in this case together with the additional supporting documentation filed by AEP Central and Cities in this proceeding as discussed in Finding of Fact No. 16. 8. No contested issues of fact beyond those that were fully litigated, argued, and heard by the SOAH ALJs in Docket No. 28840 have been raised in this proceeding; therefore, there is no need for any further evidentiary hearing on the merits on recoverable rate case expenses in addition to those already held in Docket No. 28840. 9. When the issue of the quality of the work underlying Dr. Gooclfriend's testimony in Docket No. 28840 was litigated before and the issue of the recoverability of her rate case expenses was briefed to the SOAH ALJs, Cities had the opportunity to challenge the quality of AEP Central's ex~' substantive work and the recovery of their rate case expenses under the standard applied by the SOAH ALJs to Dr. Gooclfriend's expenses. Cities failed to take advantage of that opportunity and no additional evidentiary hearing on the merits is appropriate in this proceeding as to that matter. VI. Ordering Paragraphs In accordance with these findings of fact and conclusions of law, the Commission issues the following Order: 27 DOCKET NO. 31433 ORDER PAGE 12 1. The additional supporting documentation filed by AEP Central and Cities on September 9, 2005, and by AEP Central on September 16 and October 10, 2005, as discussed in Finding of Fact No. 16 above, is admitted into the evidentiary record of this Docket No. 31433. 2. To the extent provided in this order, the requests by AEP Central and Cities for determination of their reasonable and necessary rate case expenses for Docket No. 28840 are granted. 3. As set forth in Finding of Fact No. 34, AEP Central is authorized to surcharge, over a three· year period, the aggregate rate case expenses for Docket No. 28840 found reasonable and necessary in Finding of Fact No. 33. 4. AEP Central shall file tariff sheets consistent with this Order (compliance tarifi) no later than 20 days after receipt of this Order. The Compliance tariff, and all filings related to it, shall be filed in Tariff Control Number 32385 and shall be styled: Compliance Tariff of AEP Texas Central Company Pursuant to Final Order in Docket No. 31433 Severed from Docket No. 28840. The Filing shall include a transmittal letter stating that the tariffs attached are in compliance with this Order, giving the docket number, date of this Order, a list of tariff sheets filed, and any other necessary information. The timetable for review of the compliance tariff shall be established by the Commission's ALJ assigned to the tariff. In the event any sheets are modified or rejected, AEP Central shall file proposed revisions to those sheets in accordance with the Commission's ALJ. All subsequent filings in connection with the compliance tariff (i.e., requests for extensions, textulll corrections, revisions) shall be filed in the Tariff Control Number provided above, and styled as set forth above. After issuance of the final order, no further filings other than those pertaining to a motion for rehearing shall be made in this docket. . 5. As set forth in Finding of Fact No. 35, AEP Central may seek to recover in its next rate case expenses in connection with Docket Nos. 28840 and 31433 that it incurs after June 2005 and Cities' rate case expenses incU!Ted in connection with Docket No. 28840 and 31433 that 28 DOCKET NO. 31433 ORDER PAGE13 exceed the amounts authorized to be recovered herein, to the extent such additional expenses are found reasonable and necessary. 6. 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 herein, are denied. SIGNED AT AUSTIN, TEXAS the ~ <( day of /J1~e,I_ 2006. PUBLIC UTILITY COMMISSION OF TEXAS ARSLEY, CO IONER /~~~./L_ BARR ~=RMAN, COMMISSIONER q:lcadm\on!enlfinaJ\31000\31433fu.doc 29 TARIFF CONTROL NO. 32385 PUBLIC UTILITY COMMISSION OF TEXAS COMPLIANCE TARIFF OF AEP TEXAS CENTRAL COMPANY PURSUANT TO FINAL ORDER IN DOCKET NO. 31433 SEVERED FROM DOCKET NO. 28840 MARCH 14, 2006 TABLE OF CONTENTS SECTION FILENAME PAGE Transmittal letter Letter - re Compliance RCE tariff.doc 2 Attachment A Rate Case Surcharg Rider,doc 3 Attachment B Rate Case ExP Rider Final Retail.xis 4-7 •. ~··.) ~.I _.,. . '\ :.. :;:' ;' . . ·' '-· -""J ...._;. .. ' , • .,, ' _, ·,·· ', 1 IY ~ 30 March 14, 2006 AEP Texas Central Company 400 WasJ 15Jh StroeJ, SuiJe 1500 Austin, lX 78701 James R. Galloway · Central Records Public Utility Commission of Texas 170 I N. Congress Austin, Texas 78711 Re: Tariff Control No. 32385 ·Compliance Tariff ofAEP Texas Central Company Pursuant to Final Order in Docket 31433 Severedfrom Docket No. 28840 Dear Mr. Galloway: Enclosed is the Rider RCS - Rate Case Surcharge tariff sheet for Retail Delivery Service of AEP Texas Central Company (TCC) filed herewith in compliance with the Final Order in Docket No. 31433, Proceeding To Consider Rate Case Expenses Severed From Docket No. 28840 (Application of AEP Texas Central Company For Authority To Change Rates issued on March 3, 2006. The Rider RCS - Rate Case Surcharge tariff sheet is the only tariff that is the subject of this filing and is enclosed as Attachment A, and the worksheets supporting the tariff sheet are enclosed as Attachment B. TCC proposes that the attached rate schedules be effective for bills rendered on and after March 30, 2006, which is the first billing cycle for April 2006. TCC requests that the Administrative Law Judge (ALJ) assigned. to this Tariff Control Number establish a procedural schedule allowing for that effective date. TCC requests that the tariffs be effective for billings on and after the effective date of the tariff to avoid potential implementation issues for TCC and the Retail Electric Providers. As set forth in Attachment B, in addition to the Retail Delivery Service surcharge set forth in Rider RCS, TCC will also collect the wholesale jurisdictional allocated portion of the Docket No. 31433 rate case expenses from Wholesale Transmission customers served under TCC's Open Access Transmission Tariff (OATT). If you have any questions, please do not hesitate to contact me at 5124814543. Thank you for your consideration in this matter. Sincerely, ~~~ Regulatory Case Management cc: All parties ofrecord in Docket No. 28840. Encl. 2 31 AEP TEXAS CENTRAL COMPANY Attachment A TARJFF FOR ELECTRJC DELIVERY SERVICE Applicable: Entire System Chapter: 6 Section: 6.1.1 Section Title: Delivery System Charges Revision: Original Effective Date: March 30, 2006 6.1.1.14.5 Rider RCS - Rate Case Surcharge AVAILABILITY: Rider RCS is desigued to recover Commission approved rate case expenses associated with PUCT Docket No. 28840. 1 Rider RCS is applicable to electric delivery service from the Company during the periods this schedule is in effect, and will be billed along with the other delivery service charges. Charges associated with Rider RCS will be determined in accordance with the applicable fee listed below. This schedule will be in effect from the first billing cycle of April 2006 and will end with the last billing cycle of March2009. MONTHLY RATE OTHER THAN FOR TRANSMISSION VOLTAGE SERVICE: The monthly charge shall be determined by multiplying the appropriate Rider RCS Fee in the table below by the current month's billing kWh. Rate Schedule Fee Residential Service $0.000059 per kWh Secondary Service Less than or Equal to 10 kW $0.000119 per kWh Secondary Service Greater than I 0 kW $0.000047 per kWh Primary Service $0.000026 per kWh Lighting Service $0.000119 per kWh MONTHLY RATE FOR TRANSMISSION VOLTAGE SERVICE: The RCS for the Transmission Service Class shall be collected on a revenue basis by applying the factor below to Transmission and Distribution base rate revenue. Base rate revenue is defined as the monthly sum of the distribution system charges, metering charge, customer service charge, transmission system use charges, and Rider TCRF charges. Rate Schedule Base Revenue Factor Transmission Service 0.00242 NOTICE: This Rate Schedule is subject to the Company's Tariff and Applicable Legal Authority. 1 The Rate Case Expense allocated to Retail Customers is 64.63% of the total approved rate case expenses in Docket No. 31433 (severed ftom Docket No. 28840). The Rate Case Expense allocated to Wholesale Transmission Customers is 35.37% of the total approved rate case expense in Docket No. 31433. 140 3 32 Attachment B Page 1 of 4 Allocation of Rate Case Expenses Total Approved Rate Case Expenses (1) $4,288,279 Wholesale Transmission Rate Base Allocation Factor (2) 35.37% Distribution Rate Base Allocation Factor (2) 64.63% Wholesale Transmission Total Revenue Requirement $1,516,933.52 Distribution Total Revenue Requirement $2,771,495.48 3-Year Recovery Annual Revenue Requirement Wholesale Transmission $505,644.51 Distribution $923,831.83 Wholesale Transmission Rate Case Surcharge Factor Development Wholesale Transmission Annual Revenue Requirement $505,645 Test Year ERGOT 4CP kW 53,520,537 per average 4CP per year $0.00945 monthly rate case expense surcharge for wholesale transmission service per 4CP kW (3) $0.00079 Notes: 1 Final Order Docket No. 31433 Total Rate Case Expenses AEP TCC recoverable rate case expenses $2,938,130 Cifies' recoverable rate case expenses $1,350, 149 Total Docket No. 28840 rate case expenses $4.288,279 2 Jurisdictional allocation based on rate base. Schedule 2 - Final Order dated August 15, 2005 Wholesale Transmission Rate Base 471,655,044 35.37% Distribution Rate Base 861,731,781 ~~~'"-"-,~~~~~~~ 64.63% 1,333,386,825 100.00% 3 In addition to the TCOS wholesale transmission access fee, TCC TSP shall bill a monthly rate of $0.00079 per kW of coincident peak demand for three years after the effective date of the rate case expense surcharge rider. 4 33 LINE DESCRIPTION T&D Revenue Rate Case 1 Allocator Expense Allocation kWh Surcharge Revenue Difference 2 3 Annual Rate Case Expense Revenue Requirement $923,832 4 5 Residential 52.32% $483,306 8,230,446,543 $0.000059 $485,596 $2,290 6 7 Secondary 5 ·1 0 kW 3.42% $31,565 475,856,859 8 Lighting 5.92% $54,662 249,521,076 9 Total Secondary 5 10 kW 9.33% $86,227 725,377,935 $0.000119 $86,320 $93 10 11 Secondary> 10 kW Non-I DR 26.82% $247,760 5,243,542,742 12 Secondary> 10 kW IDR 0.90% $8,342 184,389,689 13 Total Secondary> 10 kW 27.72% $256, 103 5,427,932,431 $0.000047 $255, 113 ($990) 14 15 Primary Non-IDR 1.02% $9,424 330,585,571 16 Primary IDR 5.94% $54,832 2 116,659,683 17 Total Primary 6.96% $64,256 2,447,245,254 $0.000026 $63,628 ($628) 18 19 20 The rate case expenses to be collected from the Transmission Class shall be collected on a revenue basis by applying the factor 21 shown below to the total of the distribution service, transmission service, customer service, meter service, and TCRF revenues. 22 23 T&D Revenue Rate Case Proposed % of T&D 24 Allocator Expense Allocation T&D Revenue Revenue 25 Transmission 3.67% $33,940 $13,996,621 0.00242 26 Transmission Proposed T&D Revenue $13 996,621 0.00242 $33,872 ($68) 27 28 Total Retail 100.00% $923,832 $924,529 29 30 Rate Design Difference $698 31 Rate Design Percent Difference 0.08% 32 >- "d ii 33 Notes: ~ g. 34 The Transmission Class rate case expense % of revenue is based on the percent of Transmission Class rate case N~ 35 expense allocation I proposed T&D revenue. 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Anderson, Jr. Honorable Rolando Pablos Public Utility Commission of Texas 1701 N. Congress Ave. ·:. Austin, Texas 7870 I Re: Docket No. 40742, Compliance Tariff Pursuant to Final Order in Docket No. 38986 (Application ofEntergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment) Docket o. 39896; OAH Docket No. XXX-XX-XXXX; Application of Entergy Texas, Inc. for Authorz to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment Dear Commissioners: Entergy Texas, Inc. (ETI) has reviewed the corrections to the Commission's final order in Docket No. 39896 proposed in the motion for rehearing of the Commission Staff. ETI agrees that these technical corrections are necessary so that the order will be consistent with the Staff number runs and with the Commission decisions that result in the $27 .7 million revenue increase approved in this case. ETI further understands that these corrections are not opposed by any party. The date for the filing of compliance tariffs by the Company, under the Commission's current order, is October 4, 2012. To support implementation of new rates in as timely a fashion as possible (particularly given that the new rates relate back to service rendered on and after June 30, 2012), to support synchronizing the rate increase with the credit being implemented in ETI Docket No. 40542, 1 and in light of the absence of opposition to the Staffs proposed changes, it is ETl's intent to file its compliance tariffs on October 4th consistent with the most current Staff number run. This number runs produces the $27.7 million revenue increase approved by the Commission, and reflects the ministerial corrections proposed in the Staffs recent motion for 1 Application of Entergy Texas, Inc. for Authority to Implement New Rough Production Cost Equalization Adjustment (RPCEA) Rate. 37 DUGGINS WREN MANN & ROMERO, LLP September 28, 2012 Page2 rehearing (but not yet reflected in the Commission's order). If the Commission makes any changes to its rulings in response to motions for rehearing that affect the approved revenue requirement or rates, ETI will address those changes in the tariff compliance process at that time. Resp cc: Parties of record l 38 PUC DOCKET NO. 34800 SOAH DOCKET NO. XXX-XX-XXXX APPLICATION OF ENTERGY § GULF STATES, INC. FOR § AUTHORITY TO CHANGE RATES § AND TO RECONCILE FUEL § COSTS § ORDER 1 This order addresses the application of Entergy Gulf States, Inc. (EGSI) for authority to change rates and reconcile fuel costs. The docket was processed in accordance with applicable statutes and Public Utility Commission of Texas rules. EGSI, Commission Staff, the Office of Public Utility Counsel (OPC), the Community Associations of the Woodlands (CATW), the Entergy Texas, Inc. Service Area Cities' Steering Committee (Cities), the State of Texas, Texas Industrial Energy Consumers (TIEC), Texas Legal Services Center (TLSC), Texas Ratepayers' Organization to Save Energy (Texas ROSE), Wal-Mart Stores Texas, LLC , through their duly authorized representatives (Wal-Mart) (collectively, signatories) filed a stipulation and settlement agreement that resolves all of the issues in this proceeding. The Kroger Company and TX Energy, LLC did not sign the stipulation and do not oppose it. Consistent with the stipulation, EGSI' s application is approved. The Commission adopts the following findings of fact and conclusions of law: I. Findings of Fact Procedural History I. On September 26, 2007, EGSI filed an application for approval of: (I) base rate tariffs and riders designed to collect a total non-fuel revenue requirement for the ' On December 31, 2007, EGS! jurisdictionally separated pursuant to ~ 39.452(e) of 1he Public U1ility Regulatory Act (PURA), TEX. UTIL. CODE ANN. Title 2 and Entergy Texas, Inc. (ET!) succeeded to EGSl's certificate of 39 PUC Docket No. 34800 Order Page 2of15 SOAH Docket No. XXX-XX-XXXX Texas retail jurisdiction of $605 million; (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying EGSI's application; (3) a request for final reconciliation of EGSl's fuel and purchased power costs for the reconciliation period from January I, 2006 to March 31, 2007, as well as deferred costs from prior proceedings; and (4) certain waivers to the instructions in RFP Schedule V accompanying EGSI' s application. 2. The 12-month test year used in EGSl's application ended on March 31, 2007. 3. EGSI 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 EGSI's Texas service territory. EGSI also mailed notice of its proposed rate change to all of its customers. Additionally, EGSI timely served notice of its statement of intent to change rates on all municipalities retaining original jurisdiction over its rates and services. 4. The following parties were granted intervenor status in this docket: OPC, Alliance for Retail Markets (ARM), CATW, Cities, Kroger Company, State, TIEC, TLSC, Texas ROSE, TX Energy, LLC, and Wal-Mart. 2 Commission Staff was also a participant in this docket. 5. On October I, 2007, the Commission referred this case to the State Office of Administrative Hearings (SOAH) for processing. 6. EGSI appealed the rate decisions adopted by the Cities of Chester, Woodville, Ames, Dayton, Devers, Liberty, New Waverly, Riverside, Trinity, Bedias, Bremond, Caldwell, Calvert, Franklin, Madisonville, Somerville, Patton Village, Cut and Shoot, Willis, Plum Grove, Shepherd, Oak Ridge North, Normangee, Daisetta, Hardin, Corrigan, Groveton, Anderson, Kosse, North Cleveland, Woodloch, Midway, Panorama Village, Taylor Landing, Rose Hill Acres, China, Hearne, Bevil Oaks, Colmesneil, Kountz, Nome, Lumberton, and Todd Mission. convenience and necessity for its Texas retail jurisdiction. For continuity and ease of reference. EGSI, Comm'ission Staff, and intervenors have continued to make rett:Tcnce to EGSI for purposes of pleadings in this docket. 2 OPC, ARM, Cities, Kroger Company, Stale, and TIEC were granted party Slatus on October 22, 2007. See Prehearing Conference Tr. at 6. 40 PUC Docket No. 34800 Order Page 3of15 SOAH Docket No. XXX-XX-XXXX 7. As provided for in Order Nos. 3, 9, 12, 14, and 23, the SOAH administrative law judges (ALJs) consolidated EGSI's appeals of the rate decisions adopted by the cities in Finding of Fact No. 6. 8. Cities participated in this case representing the Cities of Beaumont, Bridge City, Conroe, Groves, Houston, Huntsville, Navasota, Nederland, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Vidor, and West Orange. These municipalities have adopted rates consistent with the stipulation discussed below. 9. The Commission established in its Order on Appeal of Order No. 8 an effective date for EGSI's proposed rate change of September 26, 2008. I 0. On April 8, 2008, the State filed a motion for partial summary decision regarding the continued applicability of the 20% base rate discount for state institutions of higher education under § 36.351 of the Public Utility Regulatory Act, TEX. UTIL. CODE ANN.§§ l l.OOl-66.016 (Vernon 2007 & Supp. 2008)(PURA). 11. On July 16, 2008, the SOAH ALJs issued a proposal for decision (PFD) recommending that the Commission grant the State's April 18, 2008 motion for partial summary decision. 12. On August 15, 2008, the Commission entered an order adopting the PFD on the State's motion for partial summary decision. 13. The Commission entered an order on November 4, 2008, extending the effective date ofEGSI's proposed rate change until November 27, 2008. 14. Commission Staff, State, and TIEC filed a non-unanimous stipulation (NUS) on May 19, 2008. EGSI and certain other parties filed a separate NUS on May 20, · 2008. 3 The EGSI NUS was opposed by Commission Staff, State, and TIEC. A hearing was held on both NUSs on June 23 through July 2, 2008. 15. At Open Meetings on October 23 and November 5, 2008, the Commission considered a PFD from the SOAH ALJs which recommended resolution of the rate 41 PUC Docket No. 34800 Order Page4of15 SOAH Docket No. XXX-XX-XXXX case through adoption of the EGSI NUS. On November 7, 2008, the Commission issued its order on remand rejecting the PFD and remanding the docket to SOAH for a hearing on the merits ofEGSI's original application. 16. During the November 5, 2008 Open Meeting, EGSI agreed to extend the statutory jurisdictional deadline in this docket to March 2, 2009. EGSI subsequently agreed to extend the statutory jurisdictional deadline to March 16, 2009. 4 17. The SOAH ALJs granted ARM's motion to withdraw as an intervenor on December 2, 2008, pursuant to Order No. 49. 18. The hearing on the merits on remand took place on December 3 and 4, 2008, and December 8 through December 12, 2008. The hearing was recessed on December 12, 2008, in order to allow the parties to work on concluding a settlement. 19. On December 16, 2008, the signatories submitted a settlement term sheet to reflect their agreement in principle resolving all outstanding issues regarding EGSI's application, including those issues raised by the Commission in its November 7, 2008 order on remand. 20. On December 16, 2008, the signatories submitted an agreed motion to implement interim rates. 21. On December 19, 2008, the SOAH ALJs filed Order No. 52, granting interim approval of rates consistent with the settlement term sheet, effective with bills rendered on and after January 28, 2009, for usage on and after December 19, 2008. 22. On February 5, 2009, the signatories submitted a stipulation resolving all outstanding issues in this docket. 23. On February IO, 2009, the SOAH ALJs filed Order No. 56, returning this docket to the Commission. 3 The EGSJ NUS was subsequently amended on June 27, 2008. 4 EGSJ letter filed February 18. 2009. 42 PUC Docket No. 34800 Order Page 5of15 SOAH Docket No. XXX-XX-XXXX Description o(the Stipulation and Settlement Agreement 24. The signatories agree that EGSI will institute an overall increase in base rate revenues of$46.7 million. 25. The signatories agree to a reasonable return on equity for EGSI of I 0.00%. 26. The signatories agree that the cost of service underlying the base-rate revenue increase does not include any unreasonable or unjust expenses. 27. The signatories agree that EGSI will implement a rate-case-expense rider to recover $2.3 million per year for three years. The rate-case expenses will be allocated to customer classes based on total base-rate revenues. The rates established under the rate-case expense rider will be determined based on energy consumption in kilowatt-hours (kWh), except for the Large Industrial Power Service (LIPS) customer class, whose rates will be set on a kilowatt (kW) basis. 28. The Signatories agree to leave the mechanisms for recovery of EGSI's municipal franchise-fee riders unchanged as a result of this docket. 29. The Signatories agree that EGSI's proposed Market Value Energy Rider (MVER) will not be offered as a result of this docket. 30. The signatories agree that the Incremental Purchased Capacity Recovery Rider (IPCR) will expire contemporaneously with the implementation of rates approved in Order No. 52. 31. The signatories agree that the base-rate revenue increase, the rate-case expense rider and the municipal franchise-fee riders addressed in the stipulation became effective for bills rendered on and after January 28, 2009 for usage on and after December 19, 2008, as approved in Order No. 52. 32. The signatories reached the following specific agreements regarding rate design as a part of the overall resolution of this docket: a. Supplemental Short Term Service (SSTS). Rate Schedule SSTS will terminate six months after a final, appealable order approving the stipulation is issued by the Commission in this docket. Beginning with the 43 PUC Docket No. 34800 Order Page 6of15 SOAH Docket No. XXX-XX-XXXX base rates implemented as a result of this stipulation, EGSI will bill SSTS usage as follows: (SSTS charges+ LIPS charges)/2. b. Interruptible Service (IS). Rate Schedule IS will be modified as follows: i. 30-minute notice service is eliminated; ii. The credit for 5-minute notice service is reduced to $3.75/kW- month; m. The credit for no-notice service is reduced to $4.88/kW-month; 1v. The credits shall be applied to the· LIPS and LIPS-Time of Use (TOU) tariffs (current High Load Factor Service (HLFS) and Large Power Service (LPS) customers will be transferred to LIPS); and v. Rate Schedule IS remains closed to new business. c. Competitive Generation Service. EGSl's competitive generation-service proposal shall not be withdrawn, but shall be severed from this docket and addrt><~ed in a separate docket wherein the Commission will (a) exercise its authority to approve, reject, or modify EGSI's proposal; and (b) address , any costs unrecovered as a result of the implementation of the d ., ·>neons Electric Service Charges. No change shall be made to Miscellaneous Electric Service Charges. e. Lighting Class Rates. Lighting-class rates for all lighting fixtures shall be designed in a manner so that each fixture is charged a uniform base-rate percentage increase as established for the entire lighting class. f. Additional Facilities Charge (AFC). Rate Schedule AFC, governing additional-facilities charge, will be designed to result in a reduction to 1.49%, with the resulting revenue reduction allocated among those customer classes with AFC revenue based on the percentage of AFC revenues in each customer class. 44 PUC Docket No. 34800 Order Page7 oflS SOAH Docket No. XXX-XX-XXXX g. Economic as Available Power Service/Standby Maintenance Service. No substantive changes shall be made as a result of this docket to: (a) Rate Schedule EAPS, governing Economic-as-Available Power Service; or (b) Rate Schedule SMS, governing Standby Maintenance Service. h. Interconnection Terms and Conditions. No changes shall be made as a result of this docket to EGSI's terms and conditions regarding costs for interconnection of customers. i. Electric Extension Policy. No changes shall be made as a result of this docket to EGSl's electric extension policy. j. Large Interruptible Power Service. The signatories stipulate that the contract demand ratchet provisions in Rate Schedule LIPS will be retained; provided, however, that the billing demand provision contained in Paragraph V of Rate Schedule SSTS will no longer apply to customers taking service under Rate Schedule LIPS after Rate Schedule SSTS terminates. 33. The signatories agree to the class-cost allocation set forth in Attachment A to the stipulation and further agree that this allocation is reasonable. 34. The signatories agree to a River Bend nuclear generating station 20-year life extension adjustment to EGSl's calculation of nuclear depreciation and decommissioning costs effective January 1, 2009. 35. The signatories agree that EGSI will reduce depreciation expense related to EGSl's steam production plants by the amount of $2,731,478 on a total Texas retail basis effective January 1, 2009. 36. The signatories agree that EGSl will present a new depreciation study as part of its next base-rate case, or by January 5, 2010, whichever is earlier. 37. The signatories agree that the base-rate increase, rate riders, and associated rate design and class-cost allocation agreed to in the stipulation are reasonable and are 45 PUC Docket No. 34800 Order Page 8of15 SOAH Docket No. XXX-XX-XXXX reflected in the rate schedules approved by Order No. 52 and revised by errata filings on December 22, 2008, January 27, 2009, and March 5, 2009. 38. The signatories agree that EGSI will fund its Public Benefit Fund at an annualized amount of $2 million. 39. In order to include a greater portion of the eligible population in the Public Benefit Fund program, EGSI agrees to use its best efforts to contract for and implement an automatic enrollment program. EGSl's automatic enrollment program will be modeled upon the matching procedures used by other Texas utilities to identify eligible customers and will be implemented within 30 days of the Commission's filing of the final order in this case. 40. The signatories agree that EGSl will amend its low-income energy-efficiency program on a trial basis as specified in the stipulation. 41. The signatories agree that the amendment ofEGSl's low-income energy-efficiency program does not increase base rates to recover uncollected expenses associated with revenues billed under EGSI's energy-efficiency rider approved in Docket No. 35626.5 42. The signatories agree to a fuel disallowance of $4.5 million, booked in the month of a final Commission order approving the application, consistent with the stipulation. 43. The signatories agree to adopt Commission Staff's position on the following resolution of fuel-related matters set out in Commission Staff's pre-filed direct testimony: (a) recovery of sulfur dioxide (S02) and nitrous oxide (NO,) emissions revenues recorded in Account 411.8 and expenses recorded in Account 509 will be allowed as eligible fuel expense going forward until further order of the . Commission realigning such costs; (b) special circumstances should be granted to treat the costs of natural-gas call options incurred during the reconciliation period ' Application of Entergy Texas. Inc. for Approval of an Energy Efficiency Cost Recovery Factor (EECRF) Pursuantto PURA § 39. 905(b) and P. U. C. Subst. R. 25. /8/ (f). Docket No. 35626. Order (Aug. 14, 2008). 46 - PUC Docket No. 34800 Order Page 9of15 SOAH Docket No. XXX-XX-XXXX as eligible fuel expense; ( c) good cause exists to sever and defer the River Bend performance-based ratemaking (PBR) calculation for the final seven months of the reconciliation period to EGSI's next fuel reconciliation proceeding; and (d) the River Bend PBR plan should terminate in light of EGSI's jurisdictional separation. Evidence Supporting the Stipulation and Agreement 44. Considered in light of (a) the pre-filed testimony by the parties entered into evidence, and (b) the additional evidence and testimony presented by the parties during the course of the hearing on the merits on EGSI's application, the stipulation is the result of compromise from each party, and these efforts, as well as the overall result of the stipulation viewed in light of the record evidence as a whole, support the reasonableness and benefits of the terms of the stipulation. 45. The evidence addressed in finding of fact 44 demonstrates that the rates, terms, and conditions resulting from the stipulation are just and reasonable and consistent with the public interest when the merits of the issues contested by Commission Staff and intervenors are considered. 46. The stipulated revenue requirement does not include any amounts for financial- based incentive compensation. 47. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, they are reasonable and necessary for each class of affiliate costs presented in EGSl's application. 48. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, the price charged to EGSI is not higher than the prices charged by the supplying affiliate for the same item or class of items to its other affiliates or divisions, or a non-affiliated person within the same market area or having the same market conditions. 49. The Texas retail revenue requirement in the stipulation does not include any of the following expenses, whether allocated or direct-billed to EGSI: legislative advocacy expenses; entertainment; charitable contributions; advertising expense to promote the increased consumption of electricity or to promote the image of the 47 PUC Docket No. 34800 Order Page 10of15 SOAH Docket No. XXX-XX-XXXX electric utility industry; advertising products marketed by other affiliates; civil penalties or fines; any other expenses listed in PURA §§ 36.061, 36.062, and 36.063; payments made to cover costs of an accident, equipment failure, or negligence at a utility facility owned by a person or governmental body not selling power inside the State of Texas (except those made under an insurance or risk- sharing arrangement executed before the date of loss); the costs for processing a refund or credit under PURA § 36.110; any profit or loss that results from the sale of merchandise not integral to providing utility service; construction work in progress in rate base; or plant held for future use in rate base. 50. EGSI's current supplemental short-term service, Schedule SSTS, should be terminated within six months after the filing of a final, appealable Commission order in this docket, as provided for in the stipulation. 51. It is reasonable to modify EGSI's current interruptible service, Schedule IS, in accordance with the terms and conditions of the stipulation. 52. It is reasonable in light of the compromise reached in the stipulation for no substantive modifications to be made to EGSI's economic as-available power service, Schedule EAPS, or standby maintenance service, Schedule SMS. 53. The depreciation and decommissioning adjustments for nuclear production assets agreed to in the stipulation and consistent with Louisiana rate treatment are reasonable. 54. The depreciation adjustments to EGSI's steam production assets agreed to in the stipulation are reasonable. 55. The increase in storm cost accruals provided for in the stipulation is reasonable. 56. The low-income programs provided for in the stipulation are reasonable. 57. EGSI's energy-efficiency costs are recovered through a rider approved by the Commission in Docket No. 35626. 58. The PBR plan for the River Bend nuclear generating station contemplates an annual calculation of penalties and rewards. Good cause exists to sever and defer 48 PUC Docket No. 34800 Order Page 11of15 SOAH Docket No. XXX-XX-XXXX the PBR calculation for the final seven months of the reconciliation period to EGSl's next fuel reconciliation proceeding. 59. It is reasonable to terminate the application of the PBR plan to the River Bend operations on and after January 1, 2008 when Entergy Texas, Inc. no longer has an ownership interest in River Bend. 60. EGSI is entitled to a special circumstances exception for the cost of the natural-gas call options because they resulted in increased reliability of supply and reduced fuel expense. 61. The class allocation methodologies described in the stipulation are reasonable. 62. The total level of invested capital in the Texas retail revenue requirement is reasonable. 63. The EGSI stipulation proposes to collect the existing incremental franchise fees of the Cities of Beaumont, Port Arthur, and Conroe as a municipal franchise-fee rider. The Commission has reviewed its finding in paragraph 11.E of its remand order of November 7, 2008 and determines that the existing incremental franchise fees were the result of franchise agreements adopted subsequent to the passage of PURA § 39.456. II. Conclusions of Law 1. EGSI 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 EGSl and jurisdiction over the subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051, 36.001-36.111, 36.203, 39.452, and 39.455. 3. SOAH had 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. 49 PUC Docket No. 34800 Order Page 12 oflS SOAH Docket No. XXX-XX-XXXX 4. This docket was processed in accordance with the requirements of PURA and the 6 Texas Administrative Procedure Act. 5. EGSI provided notice of its application in compliance with PURA§ 36.103, P.U.C. PROC. R. 22.Sl(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3). 6. This docket contains no remaining contested issues of fact or law. 7. The stipulation, taken as a whole, is a just and reasonable resolution of all the issues it addresses, results in just and reasonable rates, terms and conditions, is supported by a preponderance of the credible evidence in the record, is consistent with the relevant provisions of PURA, and is consistent with the public interest. 8. EGSI has properly accounted for the amount of fuel and IPCR-related revenues collected pursuant to the fuel factor and Rider IPCR during the reconciliation period. 9 The revenue requirement, cost allocation, revenue distribution, and rate design implementing the stipulation result in rates that are just and reasonable, comply •· · · .ul! ratemaking provisions in PURA, and are not unreasonably discriminatory, prefer ·-:tial, v ~ial. '" Sever" , ... ,"r;Sl's proposed competitive generation service into a separate ·ket >L ' it" · ..~addressed separately is reasonable. EGS! ., .;ru1 'cd to a special circumstances exception under P.U.C. SUBST. R. ~5.236(a)(6) for the cost of natural gas call options. 12. Consistent with the stipulation, good cause exists to treat EGSI's emissions revenues and expenses referenced in finding of fact 43 as eligible fuel expense on a going-forward basis until further order of the Commission realigning such costs. 13. Based on the evidence in this docket, the overall total invested capital through the end of the test year meets the requirement in 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. 6 TEX. GOV'T. CODE ANN. Chapter 2001 (Vernon 2000 and Supp. 2007). 50 PUC Docket No. 34800 Order Page 13 of15 SOAH Docket No. XXX-XX-XXXX 14. The Commission has reviewed its finding in paragraph 11.E of its remand order of November 7, 2008 and determines that because the existing incremental franchise fees were the result of franchise agreements subsequent to the passage of PURA § 39.456, they qualify as new franchise agreements and are therefore in compliance with PURA§ 39.456 when recovered as a municipal franchise-fee rider. 15. The final resolution of the instant docket does not impose any conditions, obligations, or limitations on EGSI's right to file a base-rate proceeding and obtain rate relief in accordance with PURA. 16. Consistent with the stipulation, EGSI has met its burden of proof in demonstrating that it is entitled to the agreed upon level of Texas retail base-rate and rider revenue. 17. Consistent with the stipulation and PURA, EGSI has met its burden of proof in demonstrating that the rates are just and reasonable. III. Ordering Paragraphs In accordance with these findings of fact and conclusions oflaw, the Commission issues the following orders: I. Consistent with the stipulation, EGSl's application for authority to (a) change its rates; (b) reconcile its fuel and purchased power costs for the Reconciliation Period from January 1, 2006 to March 31, 2007, as well as deferred costs from prior proceedings; and (c) for other related relief is approved. 2. Consistent with the stipulation, the rates, terms, and conditions described in this order are approved. 3. Consistent with the stipulation, the tariffs and riders approved on an interim basis by Order No. 52 and revised by errata on December 22, 2008, January 27, 2009, and March 5, 2009, are approved. 51 PUC Docket No. 34800 Order Page 14 of lS SOAH Docket No. XXX-XX-XXXX 4. Consistent with the stipulation, EGSI shall implement the low-income programs described in this order. 5. Consistent with the stipulation, EGSl's Competitive Generation Services tariff is severed from this docket and shall be addressed in Application of Entergy Texas, 6. Inc.for Approval ofCompetitive Generation Services Tariff, Docket No. 36713. Consistent with the stipulation, EGSl's storm-cost accruals shall be increased by $2 I million for a total accrual of $3.65 million annually beginning January I, 2009, which amount will be incorporated in revenues recovered through base rates. 7. Consistent with the stipulation, EGSI shall terminate rate schedule SSTS and Rider IPCR. ' 8. Consistent with the stipulation, EGSI shall adjust depreciation decommissioning expense related to the River Bend nuclear generating station and depreciation expense related to EGSI's steam production assets. and I 9. Consistent with the stipulation, EGSI shall submit a new depreciation study. 10. Consistent with the stipulation, the Rider IPCR and fuel costs, including coal- related costs deferred from prior proceedings are reconciled and approved through March 31, 2007. 11. EGSI shall adjust its fuel over/under recovery balance consistent with the findings in this order. 12. The entry of this order consistent with the stipulation does not indicate the Commission's endorsement of any principle or methodology that may underlie the stipulation. Neither should entry of this order be regarded as precedent as to the appropriateness of any principle or methodology underlying the stipulation. 13. 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. 52 PUC Docket No. 34800 Order Page 15of15 SOAH Docket No. 4 73-08-0334 SIGNED AT AUSTIN, TEXAS the _ _ dayofMarch 2009 PUBLIC UTILITY COMMISSION OF TEXAS DONNA L. NELSON, COMMISSIONER q.\cadm\ordcrs\tinal\34000\34800fo2.doc 53 "'1 ~ (:,,,(,"/'.~,.,, PUC DOCKET NO. 37744 t.. -..,. I' •,.J~1 '~ SOAH DOCKET NO. 473-10-1962- · ., 1 I J I...• c::~'J APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSiON INC. FOR AUTHORITY TO CHANGE § RATES AND RECONCILE FUEL § OF TEXAS COSTS § ORDER This Order addresses the application of Entergy Texas, Inc. (ET!) for authority to change rates and reconcile fuel costs. ET!, Commission Staff, the Office of Public Utility Counsel (OPUC), the Steering Committee of Cities Served by ET! (Cities), 1 Texas Industrial Energy Consumers (TIEC), The Kroger Company (Kroger), and Wal-Mart Stores Texas, LLC and Sam's East, Inc. (collectively Wai-Mart), through their duly authorized representatives entered into and filed a stipulation and settlement agreement that resolves all of the issues in this proceeding except the issues related to ETl's proposal for competitive generation service. Cottonwood Energy, L.P. and the State of Texas agencies and institutions of higher education (State Agencies) did not join but do not oppose the stipulation. The Commission severed the competitive generation service issues into Docket No. 38951 2 inOrderNo.14. The Commission adopts the following findings of fact and conclusions oflaw: 1 Steering Committee of Cities is comprised of the Cities of Anahuac, Beawnont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota. Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange. 2 Application of Entergy Texas. Inc.for Approval of Competitive Generation Service Tariff (Issues Severed From Docket No. 37744), Docket No. 38951. PUC Docket No. 37744 Order Page 2 of 15 SOAH Docket No. XXX-XX-XXXX I. Findings of Fact Procedural History I. On December 30, 2009, ET! filed an application requesting approval of (1) base rate tariffs and riders designed to collect an overall revenue requirement of $1,758.4 million, which includes a total non-fuel retail revenue requirement of $838.3 million (base rate revenues of $486 million plus revenue from riders of $352.3 million); (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying ETl's application; (3) a request for finiil reconciliation of ET!' s fuel and purchased power costs for the reconciliation period from April 1, 2007 to June 30, 2009; and (4) certain waivers to the instructions in RFP Schedule V accompanying ETI's application. 2. The 12-month test year employed in ETl's filing ended on June 30, 2009. 3. ET! 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 ET!' s Texas service territory. ETI also mailed notice of its proposed rate change to all of its customers. Additionally, ET! timely served notice of its statement of intent to change rates on all municipalities retaining original jurisdiction over its rates and services. ET! also published one-time supplemental notice by publication in newspapers and by bill insert. 4. The following parties were granted intervenor status in this docket: OPUC, Cities, Cottonwood, Kroger, State Agencies, TIEC, and Wal-Mart. Commission Staff was also a participant in this docket. 5. On January 4, 2010, the Commission referred this case to the State Office of Administrative Hearings (SOAH) for processing. 6. On February 19, 2010, the ALls issued Order No. 3, which approved an agreement between ET!, Staff, Cities, State Agencies, OPUC, TIEC, Kroger, and Wal-Mart, to ( 1) establish an interim rate increase of $17 .5 million annually above ET!' s then-existing base rates commencing with service rendered on and after May 1, 2010 subject to true-up and refund for service rendered prior to September 13, 2010 to the extent final 55 PUC Docket No. 37744 Order Page3of 15 SOAH Docket No. XXX-XX-XXXX overall rates established by the Commission amounted to less than a $17.5 million rate increase; (2) extend the jurisdictional deadline by which the Commission must issue a final order on the Company's rate request from July 5, 2010 to November l, 2010; (3) establish a September 13, 2010 effective date for rates such that, notwithstanding the extension of the jurisdictional deadline, the final overall rates established by the Commission would relate back to service rendered on and after September 13, 201 O; (4) require ET! to publish supplemental notice, once in newspapers and by a bill insert, setting forth the effect of its proposed rate change in terms of the percentage increase in non-fuel revenues; and ( 5) establish a procedural schedule and discovery deadlines for this proceeding. Order No. 3 also granted Mr. Kurt Boehm's motion for admission pro hac vice as counsel for Kroger and ETI's February 3 and February II, 2010 petitions for review of cities' ordinances and motions to consolidate with respect to the rate decisions adopted by the Cities of Ames, Anderson, Bedias, Bevil Oaks, Bremond, Caldwell, Calvert, Chester, China, Colmesneil, Corrigan, Cut and Shoot, Daisetta, Dayton, Devers, Franklin, Groveton, Hardin, Hearne, Iola, Kosse, Kountze, Liberty, Lumberton, Madisonville, Midway, New Waverly, Normangee, Nome, Patton Village, Plum Grove, Riverside, Rose Hill Acres, Somerville, Taylor Landing, Todd Mission, Trinity, and Woodville. 7. On June 14, 2010, the ALls issued Order No. 6 granting Staff's June l, 2010 motion and severing rate case expense issues to Docket No. 38346.3 Through Order No. 6, the AUs also granted ETI's March 12, April 29, and May 17 petitions for review and motions to consolidate with respect to the rate decisions adopted by the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Panorama Village, Pine Forest, Pinehurst, Port Arthur, Port Neches, Roman Forest, Rose City, Shenandoah, Shepard, Silsbee, Sour Lake, Splendora, Vidor, West Orange, Willis, Woodbranch Village, and Woodloch. 3 Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No. 37744, Docket No.38346. 56 PUC Docket No. 37744 Order Page4of15 SOAH Docket No. XXX-XX-XXXX 8. The hearing on the merits commenced on July 13, 2010 and was immediately recessed in order to facilitate settlement negotiations. The hearing was again convened on July 15, 2010, at which time the signatories announced their intent to continue settlement discussions to resolve all issues related to the Company's application with the exception of those related to ETl's proposal for competitive generation service (CGS) and associated riders. 9. On August 6, 2010, the signatories submitted the stipulation resolving all outstanding issues regarding the Company's application with the exception of those related to ET!' s CGS proposal. Under the stipulation, ET! will be allowed to implement base rate tariffs and riders designed to collect an overall revenue requirement of$1,614.9 million,4 which includes a total non-fuel retail revenue requirement of $694.9 million (base rate revenues of $599 million plus revenue from riders of $95.9 million). The signatories also submitted, on August 6, 20 I 0, an agreed motion to revise interim rates and to consolidate the severed rat~case expense docket. The interim rates requested in the agreed motion mirrored the final rates proposed for Commission approval in the stipulation. The agreed motion further requested that the ALls consolidate with the instant proceeding Docket No. 38346, related to severed Docket No. 37744 rate case expense issues, and admit the parties' pre-filed exhibits into evidence. 10. On July 16 and July 20, 2010, the AUs held the hearing on the merits with respect to ETl's CGS proposal. 11. On August 9, 2010, the AUs issued Order No. 12, granting approval of revised interim rates for usage on and after August 15, 2010. 12. On October 5, 20 I 0, the ALls issued a proposal for decision regarding issues related to ETl's CGS proposal. 13. On October 5, 2010, the AUs issued Order No. 13, ordering the consolidation of Docket No. 38346, related to severed rat~case expense issues, into the instant proceeding, 4 This figure includes fuel at test year prices. If current fuel prices are substituted for test year fuel prices, the overall revenue requirement figure would be $1,504.0 million. 57 PUC Docket No. 37744 Order Page 5of15 SOAH Docket No. XXX-XX-XXXX admitting evidence, and returning this docket to the Commission consistent with the agreed motion filed on August 6, 20 I 0. 14. The Commission considered this Docket at the November 10, 2010 and December I, 2010 open meetings. 15. On November 30, 20 I 0 ET! filed an unopposed motion to sever the competitive CGS issues from the settled issues in this docket. The Commission granted the motion at the December I, 2010 open meeting and the Commission's decision was memorialized in Order No. 14 issued on December 3, 2010. The CGS issues were severed into Docket No. 38951 in Order No. 14. Description of the stipulation and Settlement Agreement 16. The signatories to the settlement stipulated that ET! should be allowed to implement an initial overall increase in base-rate revenues of $59 million for usage on and after August 15, 20 I 0. The signatories further stipulated that they would request approval of interim rates by the AU s presiding or by the Commission, as necessary, to ensure timely implementation of this initial rate increase. The signatories further stipulated that ET! 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, the first billing cycle for the revenue month of May. 17. The signatories agreed that ETI's authorized return on equity shall be 10.125% and its weighted average cost of capital shall be 8.5209%. 18. The signatories stipulated that the amount of rate increase authorized under finding of fact 16 includes rate-case expenses and contemplates their full amortization in 2010, and that this amount constitutes the full and final recovery of all rate-case expenses relating to Docket No. 37744. 19. The signatories stipulated to the amount of transmission and distribution invested capital by function as of June 30, 2009 as set out in attachment I to the stipulation. 58 PUC Docket No. 37744 Order Page6of15 SOAH Docket No. 473-1"" 1962 20. The signatories stipulated that the Company's proposed purchased-power recovery rider will not be approved in this docket, and purchased capacity costs will be included in base rates. 21. The signatories stipulated that the Company's proposed transmission cost recovery factor (TCRF) will not be approved in this docket. The signatories stipulated to the baseline values as shown in attachment 2 to the stipulation to be used in the Company's request, if any, for a TCRF in a separate proceeding. 22. The signatories agreed that ETI's proposed cost-of-service adjustment rider and formula rate plan will not be approved in this docket. 23. The signatories stipulated that the Company's proposed renewable-energy-credit rider will not be approved in this docket, and the Company's renewable-energy-credit costs shall be recovered in base rates. The signatories further stipulated that a transmission customer that opts out pursuant to P.U.C. SUBST. R. 25.1730) shall receive a credit that offsets the amount of renewable-energy-credit costs that are recovered in base rates from the transmission customer. 24. The signatories agreed that ETI's proposed remote-communications-link rider should be approved as filed by the Company. 25. The signatories agreed that ETI's proposed market-valued-energy-reduction service rider will not be approved in this docket. 26. The signatories reached the following specific agreements regarding rate design as a part of the overall resolution of this docket: a. Rate Schedule IS. Rate Schedule IS will be opened to new business. In the Company's next base-rate case, the amount of interruptible credits recoverable from Texas retail customers shall be limited to an increase of $1 million more than the amount requested in this docket (or a total of $6.8 million); provided, however, that in the next rate case, the Company may request an exception to this limitation upon a showing that the test-year credit amount in excess of the $6.8 million cap is both cost effective and necessary to meet the Company's generation reserve margin requirement. The signatories further agreed that the 59 PUC Docket No. 37744 Order Page 7of15 SOAH Docket No. XXX-XX-XXXX Company will not offer additional interruptible service if the availability of total interruptible service supplied by the Company under all interruptible service riders exceeds 5% of the projected aggregate Company peak demand unless the additional level of interruptible service offered in excess of the 5% cap is both cost effective and necessary to meet the Company's generation reserve margin requirement. To the extent that the credit amount or participation level exceeds the limitations described in this paragraph and the Company includes test-year credits over the $6.8 million credit-amount cap or additional participation in excess of the 5% participation-level cap in its next rate case, the Company shall have the burden to prove whether those test-year credits or participation levels meet the standards established in this paragraph for inclusion in the test year. The standards in this paragraph are in addition to any requirements in PURA for inclusion of costs in rates. The signatories further agreed to the Schedule IS revisions shown on attachment 3 to the stipulation. b. Rate Schedule !HE. The signatories agreed that no change shall be made to rate schedule !HE in this docket. c. Lighting Class Rates. The signatories stipulated that the language under the paragraph relating to rate group C in rate schedule SHL will be revised to reflect that, where the Company agrees to install facilities other than its standard street light fixture and lamp as provided under Rate Group A, a lump sum payment will be required, based upon the installed cost of all facilities excluding the cost of the standard street light fixture and lamp, and the customer will be billed under rate group A. e. Electric Extension Policy. The signatories agreed to the line-extension terms and conditions as reflected in attachment 4 to the stipulation. f. Life-of-Contract Demand Ratchet. The signatories agreed that the life-of-contract demand ratchet provision in rate schedules Large Industrial Power Service, Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day, Large General Service, and Large General Service-Time of 60 PUC Docket No. 37744 Order Page8 oflS SOAH Docket No. XXX-XX-XXXX Day shall be excluded from rate schedules in ETI's next rate case. The signatories further stipulated 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 shall not exceed the level in effect on August 15, 2010 for existing customers. g. Residential Customer Charge. The signatories agreed that the residential customer charge shall be increased to $5.00. h. Non-Sufficient Funds Charge. The signatories agreed that the non-sufficient funds charge shall be increased to $15.00. 27. The signatories agreed to the class cost allocation set forth in attachment 5 to the stipulation. 28. The signatories stipulated that the appropriate allocation between ETl's wholesale and retail jurisdictions of baseline values and costs to be included in a TCRF is to be addressed in the proceeding, if any, in which ET! seeks approval of a TCRF. 29. The signatories stipulated that no party waives its right to address in any subsequent proceeding the appropriate treatment for Texas retail ratemaking purposes of power sales between ETI and Entergy Gulf States Louisiana, L.L.C. 30. The signatories reached the following specific agreements regarding fuel-related issues as part of the overall resolution of this docket: a. Agreed Fuel Disallowance. The Company stipulated to a fuel disallowance of $3 .25 million not associated with any particular issue raised by the signatories. The disallowance will be allocated pro rata with interest over each month of the reconciliation period and reflected in the refund in Docket No. 38403.5 The signatories stipulated that the Company's fuel costs shall be finally reconciled for the reconciliation period of April 1, 2007 through June 30, 2009. b. Rider lPCR. The signatories agreed that ETI's eligible Rider IPCR costs fur the 5 Application of Entergy Texas, Inc. to Implement an Interim Fuel Refund, Docket No. 38403, Order (Sept 16. 2010). 61 PUC Docket No. 37744 Order Page 9 of15 SOAH Docket No. XXX-XX-XXXX period April 1, 2007 through the date the rider terminated shall be finally reconciled with a disallowance of $300,000. The signatories further agreed that the under-recovered balance of Rider IPCR costs shall be booked as fuel expense in the month in which the Commission issues an order adopting the stipulation; provided, however, that the under-recovered balance shall be allocated to customer classes using A&E4CP. c. Rough Production Cost Equalization (RFCE) Payments. The signatories agreed that ET! will credit an additional $18.6 million to Texas fuel-factor customers, which the· signatories stipulated represents the remaining portion of RPCE payments ETI received in 2007 that were at issue in Docket No. 35269.6 The RPCE credit shall be allocated to rate classes based on loss-adjusted kilowatt hours at plant for calendar year 2006. For customers in the Large Industrial Power Service rate class, the credit will be refunded based on the customer's actual kWh usage during the billing months of January 2006 through December 2006. Upon issuance of a final order approving the stipulation, the RPCEs shall be credited to customers as a separate one-month bill credit in the same form as the RFCEA Rider last approved in Docket No. 38098.7 ET! agreed that it will terminate all appeals related to Docket No. 35269. 31. The signatories agreed that ET! will continue its accrual of storm-cost reserves at the level of $3 .65 million annually and that this amount shall be subsumed in the base-rate revenue increase described in finding of fact 16 above. 32. The signatories agreed that ET! shall maintain River Bend depreciation rates at current levels, i.e., based on a 60-year life. River Bend decommissioning costs will be set at $2,019,000 annually, which is based upon a labor-factor escalation rate of 1.67%, an energy-factor escalation rate of 0.25%, and a waste-burial-factor-escalation rate of 6 Compliance Filing ofEntergy Texas, Inc. Regarding Jurisdictional Allocation of2007 System Agreement Payments, Docket No. 35269, Order (Jan. 7, 2009). 7 Application of Entergy Texas, Inc. for Authorily to Implement New RPCEA Rate, Docket No. 38098, Order (July I, 2010). 62 PUC Docket No. 37744 Order Page 10of15 SOAH Docket No. XXX-XX-XXXX I. 71 %, resulting in an overall escalation rate of 3.62%, and net investment yields as follows: Nuclear-Decommissioning-Trust Projected Returns Tax-Qualified Non-Tax-Qualified Investments Investment 2010 5.475% 5.057% 2011 5.837% 5.236% 2012 6.306% 5.567% 2013 6.304% 5.607% 2014 6.481% 5.896% 2015 6.493% 5.909% 2016 6.412% 5.826% 2017 6.412% 5.830% 2018 6.364% 5.790% 2019 6.316% 5.748% 2020 6.268% 5.712% 2021 6.220% 5.670% 2022 2.503% 5.458% 2023 5.817% 5.055% 2024 5.382% 4.628% 2025 5.036% 4.516% 2026-2034 4.920% 4.409% 33. The signatories stipulated that the Company's depreciation rates for non-River Bend production plant, transmission, distribution, and general plant will remain at current levels and the Company will maintain its accounting records on a prospective basis for purposes of depreciation accrual, depreciation reserve, retirements, additions, salvage, and cost of removal by FERC account. Consistencv of the Agreement with PURA and the Commission Requirements 34. Considered in light of ( 1) the pre-filed testimony by the parties entered into evidence and (2) the additional evidence and testimony admitted during the course of the hearing on the merits on the Company's application, the stipulation is the result of compromise from each signatory, and these efforts, as well as the overall result of the stipulation viewed in light of the record evidence as a whole, support the reasonableness and benefits of the terms of the stipulation. 63 PUC Docket No. 37744 Order Page 11 of lS SOAH Docket No. XXX-XX-XXXX 35. The evidence addressed in finding of fact 34 demonstrates that the rates, terms, and conditions resulting from the stipulation are just and reasonable and consistent with the public interest. 36. The total level of the Texas retail revenue requirement contemplated by the stipulation will allow ET! the opportunity to earn a reasonable return over and above its reasonable and necessary operating expense. 37. The stipulated revenue requirement is consistent with applicable provisions of PURA chapter 36 and the Commission's rules. 38. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, they are reasonable and necessary for each class of affiliate costs presented in ETl's application. 39. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, the price charged to ETI is not higher than the prices charged by the supplying affiliate for the same item or class of items to its other affiliates or divisions, or a non-affiliated person within the same market area or having the same market conditions. 40. The retail revenue requirement in the stipulation does not include any expenses prohibited from recovery under PURA. 41. A return on equity of 10.125% and a weighted average cost of capital of 8.5209% for ET! should be adopted consistent with the stipulation. 42. The agreed rate-design provisions and terms and conditions of service included in the stipulation are just and reasonable. 43. The treatment of rate-case expenses described in the stipulation is reasonable. 44. The Company's proposed remote-communications-link rider as filed by the Company is reasonable. 45. The depreciation rates agreed to in the stipulation are just and reasonable. 64 PUC Docket No. 37744 Order Page 12 of lS SOAH Docket No. XXX-XX-XXXX 46. The recovery of $2,019,000 annually for decommissioning costs of nuclear production assets based on the factors agreed to in the stipulation is reasonable. 47. A $3.65 million annual storm cost accrual is reasonable. 48. The class allocation methodologies described in the stipulation are just and reasonable. 49. The fuel and IPCR-related provisions of the stipulation are reasonable. II. Conclusions of Law I. ET! 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 ET! and jurisdiction over the subject matter of this application pursuant to PURA§§ 14.001, 32.001, 32.101, 33.002, 33.051, 36.001-.111, 36.203, 39.452, and 39.455. 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, the Texas Administrative Procedure Act, 8 and Commission rules. 5. ET! provided notice of its application in compliance with PURA§ 36.103, P.U.C. PROC. R. 22.5l(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3). 6. This docket contains no remaining contested issues of fact or law. 7. The stipulation, taken as a whole, is a just and reasonable resolution of all issues it addresses; results in just and reasonable rates, terms, and conditions; is supported by a preponderance of the credible evidence in the record; is consistent with the relevant provisions of PURA; and is consistent with the public interest. 8. ET! has properly accounted for the amount of fuel and IPCR-related revenues collected pursuant to the fuel factor and Rider IPCR. 8 TEX. GOV'TCODEANN. Chapter 2001(Vernon2007 and Supp. 2009). 65 PUC Docket No. 37744 Order Page 13 oflS SOAH Docket No. XXX-XX-XXXX 9. The revenue requirement, cost allocation, revenue distribution, and rate design implementing the stipulation result in rates that are just and reasonable, comply with the ratemaking provisions in PURA, and are not unreasonably discriminatory, preferential, or prejudicial. I 0. Based on the evidence in this docket, the overall total invested capital through the end of the test year meets the requirement in 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. 11. ET! has met its burden of proof in demonstrating that it is entitled to the level of retail base rate and rider revenue set out in the stipulation. 12. ET! has met its burden of proof in demonstrating that the rates resulting from the stipulation are just and reasonable, and consistent with PURA. III. Ordering Paragraphs I. ETI's application seeking authority to change its rates; reconcile its fuel and purchased power costs for the Reconciliation Period from April I, 2007 to June 30, 2009; and fur other related relief is approved consistent with the above findings of fact and conclusions oflaw. 2. Rates, terms, and conditions consistent with the stipulation are approved. 3. The tariffs and riders consistent with the stipulation are approved fur the initial and second step rate increases. 4. ETI's request for waivers ofRFP instructions (RFP Schedule V) is granted. 5. ETI shall adjust decommissioning expense related to the River Bend Nuclear Generating Station consistent with the terms of this Order. 6. Neither the stipulation and settlement agreement nor this Order constitutes the Commission's agreement .with, or consent to, the manner in which ET!, or any entity affiliated with ET!, has interacted with any decommissioning trust to which ET! or its ratepayers have made contributions or provided funds. Furthermore, this Order in no 66 PUC Docket No. 37744 Order Page 14 oflS SOAH Docket No. XXX-XX-XXXX way constitutes a waiver or release of any conduct, whether or not such conduct occurred before the date of this Order, that may constitute a violation of any provision of state law, including, without limitation, the rules and regulations of this Commission relating to nuclear decommissioning trust funds; or prevents the Staff of the Commission from opening an investigation and taking enforcement action relating to violations of such rules and regulations. 7. Nothing contained in this Order constitutes the consent or approval, explicit or implied, of any modification, amendment or clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River Bend Station. Without limiting the foregoing, nothing contained in this Order shall constitute the consent or approval of any modification, amendment, or clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River Bend Station, which is made to address any concerns raised by the NRC in its Request for Additional Information regarding the River Bend Station dated March 11, 20 I 0. 8. The Rider IPCR costs and eligible fuel costs requested by ET! are, consistent with this Order, reconciled through June 30, 2009, and are approved consistent with the stipulation. 9. ET! shall adjust its fuel over/under recovery balance consistent with the findings in this Order. I 0. ET! shall file an RPCEA Rider consistent with the above findings of fact and conclusions of law to be effective with the first billing cycle of the billing month immediately following the effective date of this Order.. 11. Because the final approved ~tes are equal to or higher than the interim rates adopted in Order No. 3, no refund of the interim rates authorized by Order No. 3 is necessary. 12. The interim rates approved in Order No. 12 are herby approved for the initial step rate increase contemplated by the stipulation, and ET! shall implement the second step rates for bills rendered on and after May 2, 2011, the first billing cycle for the revenue month of May. 67 PUC Docket No. 37744 Order Page 15 oflS SOAH Docket No. XXX-XX-XXXX 13. Within 30 days of the date of this Order, ET! shall file a clean copy of all of the tariffS and schedules approved in this docket and a clean copy of the attachments to the stipulation. 14. The entry of this Order consistent with the stipulation does not indicate the Commission's endorsement of any principle or method that may underlie the stipulation. Neither should entry of this Order be regarded as a precedent as to the appropriateness of any principle or methodology underlying the stipulation. 15. 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. SIGNED AT AUSTIN, TEXAS the \ 6\-h day of December 2010 PUBLIC UTILITY COMMISSION OF TEXAS DONNA L. NELSON, COMMISSIONER q:\cadm\orders\final\37000\37744fo.docx 68 SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION lNC. FOR AUTHORITY TO CHANGE § S \ b Counsel Ending Sequence No. 5SI'~- Question No.: OPUC 1-3 Part No.: Addendum: Question: If your answer to OPUC's RF! No. 1-1 is no, please provide data and other information to show that the amount being recovered as an affiliate expense related to project code F3PPWET308 in Docket No. 39896 has not also been requested for recovery in this proceeding as a rate case expense. Response: See the response to OPUC 1-1. 40295 SS15 75 ENTERGY TEXAS, INC. PUBLIC UTILITY COMMISSION OF TEXAS SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 -2011 ET! Rate Case Response of: Entergy Texas, Inc. Prepared By: J. Stephen Dingle to the Third Set of Data Requests Sponsoring Witness: Patrick J. Cicio of Requesting Party: Office of Public Utility Beginning Sequence No. Counsel Ending Sequence No. Question No.: OPUC 3-17 Part No.: Addendum: Question: a. Please explain why ET! will continue to incur expenses for negotiations related to the Calpine purchased power agreement after the test year. b. Explain in detail the Calpine PPA negotiation expenses that will be expected to be incurred in 2012 and 2013. c. Provide documentation supporting your response. Response: a. The costs "'corded in Project Code F3PPWET308 include costs associated with obtaining regulatory approval for the Calpine Contract, which processes extend beyond the test year. The Company expects to incur similar expenses in the future on an ongoing basis. b. These will be costs associated with responding to issues arising within the pending rate case in Texas, as well as participating in LPSC Docket No. U-3032 J. c. See the Project Summary for Project Code F3PPWET308 in Exhibit SBT-E. 39896 SS466 76 ENTERGY TEXAS, INC. PUBLIC UTILITY COMMISSION OF TEXAS SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 - 2011 ETI Rate Case Response of: Entergy Texas, Inc. Prepared By; J. Stephen Dingle/Joe Bennett to the Ninth Set of Data Requests Sponsoring Witness; Patrick J. Cicio/Michael P. Considine of Requesting Party: Office of Public Utility Beginning Sequence No.SS '154- Counsel Ending Sequence No. S$1:s.f- Question No.: OPUC 9-6 Part No.: Addendum: Question: a. Regarding ETI's response to OPC RF! No. 3-17, is ETI implying that any rate case expenses related to the Calpine Contract in Docket No. 39896 (e.g. RF! responses, legal fees) will be charged to F3PPWET308? Please explain your response. b. Are there any other instances where Docket No. 39896 expenses are being charged to multiple projects? If so, please identify all costs and the associated project numbers. Response: a. No rate case expenses were charged to that project code, although costs for that project code were included in ETI's costs. b. All costs pertaining to Docket No. 39896 should be recorded in Project Code F5PPETXO 11. 177 39896 ENTERGY TEXAS, INC. 2011 TX Rate Caso Page 1168 PROJECT SUMMARY ESI Project Code Description B!ll!ng Method SPO Calpine PPNProject Houslo OIRECTTX F3PPWET308 Test Year Affiliate Billings to ET!: Account Total Exclusions Pro Forma Adjusted 234000 - AJP - Affiliate 0 0 0 0 403100 - Oepreciation Exp-Serv Co AUoc 7.241 0 0 7,241 4031AM-Oeprec Exp biUed from Serv Co 5,168 0 0 5,168 408110 - Employment Taxes 11,679 0 412 12,091 426500 - other Oeductions 0 0 0 0 500000 - Oper Supervision & Engineerin 1,548 0 37 1,585 506000 - Misc Steam Power Expenses 2,931 0 70 3,001 920000 - Adm & General Salaries 209,513 0 4,361 213,874 921000 - Office Supplies And Expenses 2,035 0 0 2,035 923000 - Outside seiViOOs EmPiOYed-- -- ~--1-10.951 C--·---- 0 ----- 0 -·--···-- 110,951 --·------------------ 926000 - Employee Pension & Benefits .. ---···--··-· -------· 82,844 ~· 0 --- -555 -·---- 82,288 930200 - Miscellaneous General Expense -2,271 0 0 -2,271 Total 431,639 0 4.324 435,963 --------·-- - ----·· ------ --~---··-· '-·----'---.-- ------- Detail Bv Class· Class Total Exclusions Pro Forma Adjusted ENERGY ANO FUEL MANAGEMENT 94,945 0 1,996· 96,941 FEOERAL PRG AFFAIRS 1,206 0 -1,206 0 FOSSIL PLANT OPERATIONS 7,037 0 139 7,176 TREASURY OPERATIONS 12,539 0 245 12,764 HUMAN RESOURCES 37,837 0 .£7 37,770 LEGAL SERVICES 255,552 0 2,916 258,470 OTHER EXPENSES 3,722 0 171 3,893 FINANCIAL SERVICES 6,195 0 124 6,319 OEPRECIATION 12,409 0 0 12,409 TAX SERVICES 197 0 4 201 Total i 431,639 0 4,324 435,963 Scope of Work Statement of Purpose: The overall purpose of this project is to capture and manage costs associated wi1h the Power Purchase Agreement {PPA} from Calpine Corporation for Entergy Texas. Inc. (ETJ}. Primary Aclivilies: The primary activity associated 'Nilh lhis project is lhe negotiations of the Jong-term PPA for the delivery of electric capacity, energy and olher associated electric products from the CarviUe Facility for ETJ. Primary ProducJs or Oetiverables: The primary products or deliverables of lhis project are an executed and approved Jong-term PPA 'Nilh Calpine Corporation for the delivery of electric capacity, energy and other associated electric products from the CarviUe facility to meet ETJ"s short and Jong-term capacity needs. Justification of Billing Melhod: The costs associated with lhe project wiU include the inlernal and third-party costs associated 'Nilh the PPA"s negotiations, Amounts may nol add or tie lo other schedules due lo rounding. Project Code F3PPWET308 178 78 ENTERGY TEXAS, INC. 2011 TX Rate Case Page1169 PROJECT SUMMARY ESI Project Code Description Billing Method SPO CaJpine ?PA/Project Housto OJRECTTX F3PPWET308 development, review and intemaJ/reguJatory approval process. These costs may Jead to the execu)ion of a Jong-term PPA with Calpine Corporation for the delivery of eJectric capacity, energy and other associated eJectric products from the CarvWe FacUity Jhat wouJd benefit ETJ and shouJd therefore be charged onJy Jo ETJ via bUling method DJRECTTX. Amounts may not add or tie Jo other scheduJes due Jo rounding. Project Code F3PPWET308 179 79 PUC DOCKET NO. 40295 SOAH DOCKET NO. XXX-XX-XXXX APPLICATION OF F,NTERGY § TEXAS, INC. FOR RATE CASE § EXPENSES PERTAINING TO PUC § OF TEXAS DOCKET NO. 39896 § ORDER This Order addresses the rate-case expenses pertaining to Docket No. 39896, 1 Entergy Texas, Inc. 's last rate case. Entergy requested $8.8 million in rate-case expenses associated with Docket No. 39896-$7.6 million for Entergy's own rate-case expenses and $1.2 million for Cities' rate-case expenses. The proposal for decision in this docket was issued on February 19, 2013. In the proposal for decision, the ALJ recommended allowing Cities' rate-case expenses incurred through August 31, 2012, plus up to $75,800 in rate-case expenses as they are incurred alter August 31, 2012. The ALJ also recommended that Entergy's rate-case expenses be reduced to account for Entergy taking certain positions in the rate case regarding financially-based incentive compensation and transmission equalization expenses. The Commission considered the proposal for decision at the April 11 and April 25, 2013 open meetings. The Commission adopts in part and reverses in part the proposal for decision, including findings of fact and conclusions of law. I. Estimated Rate-Case Expenses The Commission reverses the proposal for decision regarding Cities' $75,800 in estimated rate-case expenses to be incurred after August 31, 2012. 2 In Docket No. 37772, the Commission found that approving estimated rate-case expenses for two different parties representing Cities is not in the public interest and disallowed their recovery in the rate-case expense surcharge, but did not prohibit the Cities from seeking recovery of actual rate-case 1 lpplicalirm o( Enter.l{y Texas. Inc. f , P/j SOAH DOCKET NO. XXX-XX-XXXX '"''--:c ll:.',." . /:Jg f/L,i}-/G'·"I,, " "L[frf; ,'; APPLICATION OF SOUTHWESTERN § PUBLIC UTILITY COMMISSION ELECTRIC POWER COMPANY FOR § AUTHORITY TO CHANGE RATES § OF TEXAS AND RECONCILE FUEL COSTS § ORDER ON REHEARING This Order addresses the application filed on July 27, 2012 by Southwestern Electric Power Company (SWEPCO) for authority to change its rates and reconcile its fuel costs. The primary contested issue regarding the proposed increase involves the portion of SWEPCO's share of the costs of the Turk coal plant in Hempstead, Arkansas that are allocated to Texas. SWEPCO's application sought a total-company revenue requirement of $1.033 billion, exclusive of fuel revenues. The requested Texas retail revenue requirement exclusive of fuel revenues was $329 million, which reflected an increase in annual Texas retail revenues of $83.37 million over its adjusted test-year revenues. 1 The increase primarily consists of the inclusion of the newly constructed Turk coal plant and Stall gas plant. For the fuel reconciliation period from April 1, 2009 through December 31, 2011, SWEPCO sought to reconcile a cumulative fuel under-recovery balance of $3,936,492, including interest, and proposed no surcharge. SWEPCO's reconciliation included proposed revisions to Dolet Hills Lignite Company benchmark price. The State Office of Administrative Hearings' administrative law judges (ALJs) issued a proposal for decision on May 20, 2013. The ALJs' recommended approval of the application, with certain adjustments. Regarding the Turk plant, the ALJs recommended the disallowance of all Turk costs over approximately $934 million as being imprudently incurred in continuing construction after June 2010. The ALJs further recommended that approximately $260 million be allowed for the estimated costs to retrofit the Welsh Unit 2 coal plant that SWEPCO should have undertaken instead of completing the Turk plant. However, the ALJs recommended in the 1 Rebuttal Testimony of Jennifer L. Jackson, SWEPCO Ex. 88, JLJ-1 R at 2. 00000001 PUC Docket No. 40443 Order on Rehearing Page 13 of 59 SOAR Docket No. XXX-XX-XXXX J. Fuel Reconciliation SWEPCO requested a good cause exception to recover consumables and allowances as fuel on a going-forward basis. The Commission is persuaded by the arguments of Commission Staff regarding this issue and rejects the AUs' recommendation to disallow the request. Accordingly, finding of fact 322 is modified and conclusion of law 47 is modified. K. Miscellaneous Corrections to the findings of fact and conclusions of law are necessary to appropriately reflect the Commission's determinations regarding the following issues. First, the findings regarding the unique aspects of SWEPCO' s overall compensation program do not accurately reflect the AUs' recommendation that the Commission adopts. Therefore, the Commission modifies finding of fact 147 to clarify that the portion of SWEPCO's annual and long-term incentive payments that are capitalized and that are financially-based are excluded from SWEPCO's rate base because the benefits of such payments inure most immediately and predominantly to SWEPCO's shareholders, rather than its electric customers. Also, an error in finding of fact 220 is corrected to reflect that, of SWEPCO's annual incentive compensation of $10,728,117, $3,523,732 is disallowed as financial goals. These same findings are clarified to reflect that the part of the long-term incentive compensation program that includes performance units is disallowed as being based on financial measures, and the part that includes restricted stock units is allowed - $3,130,757 is disallowed from the $5,175,829 in long-term incentive compensation. Further, in accordance with other corrections noted by the AUs in their July 2, 2013 letter, the amount of credit line fees is corrected in finding of fact 186. The Commission also modified finding of fact 242 to reflect its clarification that the test-year expenses for injuries and damages exceeds the average of the expense in the three previous years, and the amount should be disallowed completely and not amortized. Also, the ordering provisions reflect the AUs clarification that SWEPCO should provide a calculation in its compliance filing to include 12 months' weather normalized residential sales based on a 10-year normal to reflect the AUs' recommendation adopted by the Commission. 000000013 PUC Docket No. 40443 Order on Rehearing Page38 of59 SOAH Docket No. XXX-XX-XXXX General Plant 207. Asbestos removal in 1996 and the sale of an office building in 2004 should be removed from the removal cost and salvage data for FERC Account 390-General Plant for 1984-2011 upon which the net salvage rate for the account should be based. The net salvage rate of negative 3% resulting from this modification is reasonable and reduces SWEPCO's initially requested depreciation expense by $97,594 on a total Company basis and $32,938 on a Texas jurisdictional basis. Depreciation Reserve 208. The use of the remaining life depreciation method to recover differences between theoretical and actual depreciation reserves is the most appropriate method. 209. It is reasonable for SWEPCO to calculate depreciation reserve allocations on a straight-line basis over the remaining, expected useful life of the item or facility. Payroll 210. SWEPCO made two adjustments to its test-year payroll. The Company updated payroll costs by annualizing the base payroll to the salary rates in effect at the end of the test year and by recognizing the effect of the merit and general increases that were awarded in 2012. 211. Because these payroll increases were awarded in 2012, they represent appropriate known and measurable adjustments to test-year expenses. 212. SWEPCO double-counted the Turk plant payroll by including Turk plant employees in the pro Jonna payroll O&M as well as in the post-test-year adjustment. 213. SWEPCO's labor costs should be disallowed by the sum of $197,688 and $50,932, or $248,620. Incentive Compensation 214. SWEPCO sought to recover in rate base a total amount of $10,728,117 paid as annual incentive compensation to its employees and $5,175,829 paid for long-term incentive compensation. 000000038 PUC Docket No. 40443 Order on Rehearing Page39 of 59 SOAH Docket No. XXX-XX-XXXX 215. The PUC permits a utility to recover in its base rate incentives that are designed to achieve "operational measures" and that are necessary and reasonable to provide utility services, but not incentive programs that are designed to achieve "financial measures." 216. Operational measures are those designed to encourage a utility's employees to meet goals and standards relating to the efficient operation of the utility, a benefit to shareholders and ratepayers alike. 217. Financial measures are those designed to encourage employees to achieve financial targets, a benefit primarily to shareholders. 218. SWEPCO's "Regulatory," "Strategic," and "Margin Generating" annual incentive goals relate to financial measures. 219. SWEPCO's long term incentive awards in the form of performance units relate to financial measures. 220. Of SWEPCO's annual incentive compensation of $10,728,117, $3,523,732 should be disallowed as financial goals. Of SWEPCO's long-term compensation, all but $2,045,072 of the total should be disallowed as financial goals. Executive Perquisites 221. The $16,350 related to executive perquisites should not be included in rates because they provide no benefit to ratepayers and are not reasonable or necessary for the provision of electric service. Relocation 222. SWEPCO's proposed relocation expense, in the amount of $574,588, is reasonable and necessary. Pensions 223. It is reasonable to base pension expense in SWEPCO's cost of service upon the cost of $8,306,420 on a total Company basis calculated in the 2012 actuarial report prepared in accordance with FAS 87. 000000039 , PROCEEDING TO CONSIDER RATE § CASE EXPENSES SEVERED FROM § DOCKET NO. 28840 (APPLICATION OF § AEPTEXASCENTRALCOMPANYFOR § AUTHORITY TO CHANGE RATES) § § ORDER This Order addresses the recoverable rate-case expenses of AEP Texas Central Company (AEP Central) and of Cities 1 in connection with their participation in Docket No. 28840.2 As set forth in this Order, the Public Utility Commission of Texas (Commission) determines that AEP Central's recoverable rate case expenses through June 2005 are $2,938,130 and that Cities' recoverable rate case expenses are $1,350,149. As discussed herein, the Cities' expenses relating to witness Sarah Goodfriend have been reduced by one-half as recommended by the State Office of Administrative Hearings (SOAH) Administrative Law Judges in their Proposal for Decision (PFD) in Docket No. 28840. 3 This Order finds that $4,288,429 in rate-case expenses incurred by AEP Central and Cities is reasonable and necessary and authorizes AEP Central to implement a surcharge over three years to recover this amount. I. Procedural History On November 3, 2003, AEP Central filed an application seeking a change in its rates. This application was assigned Docket No. 28840, and the Commission referred the case to SOAH on November 4, 2003. SOAH issued its initial PFD in Docket No. 28840 on July 1, 2004, which contained certain findings on rate case expenses. In July and August 2004, the Commission issued two orders on remand in Docket No 28840 directing SOAH to consider further and provide further evaluation of certain specified issues, none of which involved rate case expenses. On November 1 Alice, Aransas Pass, Carrizo Springs, Dilley, Donna, Eagle Lake, Freer, Ganado, George West, Ingleside, Kingsville, LaFeria, Laguna Vista, La Joya, Leakey, Los Fresnos, Lyford, Lytle, McAllen, Mercedes, Mission, Nordheim, Odem, Pharr, Port Aransas, Portland, Port Lavaca, Poteet, Rancho Viejo, Refugio, Rio Hondo, Runge, San Benito, San Juan, Sinton, Uvalde, and Weslaco (collectively, Cities). 2 Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Order (Aug. 15, 2005). 3 Docket No. 28840, Proposal for Decision at 121-127, 205 (FOF 210-216), 209 (FOF 256) (Jul. l, 2004). DOCKET NO. 31433 ORDER PAGE2 16, 2004, SOAR issued its Remand PFD. In addition, the Commission held hearings on certain matters relating to merger savings and affiliated expenses on March 3, 4, and 7. The Commission issued its final order in Docket No. 28840 on August 15, 2005. In that order, the Commission severed the determination of the reasonableness and necessity of rate case expenses to this proceeding, Docket No. 31433. 4 While rate-case expenses were not addressed on the remand SOAR hearing and the Commission-held hearing, Cities and AEP incurred additional expenses as a result of these hearings, and submitted updated information on these additional expenses. Based on the submission, the Commission decided to sever the determination on rate-case expenses to examine this additional evidence. 5 By Order No. 1 in this proceeding, AEP Central and Cities were directed to file detailed supporting documentation of their requested rate case expenses. On September 9, 2005, AEP Central and Cities filed such supporting documentation. On September 16 and October 10, 2005, AEP Central made supplemental filings that furnished additional supporting documentation with respect to certain of its requested expenses. On October 14, 2005, the parties filed statements of position and on October 28, 2005, AEP Central filed its Motion for Ruling on Disputed Issue and Conditional Request for a Hearing. On December 12, 2005, the presiding officer issued Order No. 4, which requested clarification regarding contested issues. On December 22, 2005, the parties filed responses to Order No. 4. The parties' filings established that there are no contested factual issues in Docket No. 31433 that have not been fully litigated in Docket No. 28840. To the extent AEP Central had previously conditionally requested a hearing, that request was withdrawn by AEP Central' s December 22, 2005 filing. The sole disputed issue is the recoverability of one-half of Cities' witness Sarah Goodfriend's expenses, which the SOAH ALJs had recommended be disallowed in their PFD in Docket No. 28840 issued on July 1, 2004. Since there are no contested factual issues that have not already been fully litigated, an evidentiary hearing on the merits is not necessary or appropriate. The disposition of the sole contested issue is discussed in the subsequent section of this Order. 4 Docket No. 28840, Order at 60 (Ordering 1f 5) (Aug. 15, 2005). 5 Open Meeting Tr. at 54-62 (July 29, 2005). DOCKET NO. 31433 ORDER PAGE3 II. Recoverability of One-Half of Dr. Goodfriend's Expenses In Docket No. 28840, AEP Central submitted testimony challenging the quality of a survey that fonned the basis of testimony submitted by Cities witness, Dr. Sarah Goodfriend. 6 Following a full evidentiary hearing and briefmg on this and other issues, the SOAH ALJs recommended that one-half of Dr. Goodfriend's expenses be disallowed because they found that the methodology of the survey she conducted was ''seriously flawed." 7 In severing the issue of rate case expenses from Docket No. 28840 to this proceeding, the Commission intended that the entire evidentiary record in Docket No. 28840 on rate case expenses as well as the Commission's initial decisions be carried over to this case. Thus, the evidentiary record on the quality of Dr. Goodfriend's work underlying her testimony in Docket No. 28840 and the SOAH ALJs' findings regarding the recoverability of one-half of her expenses are before the Commission for decision in this proceeding. The purpose of the severance, however, was to evaluate the detailed supporting documentation on updated rate-case expenses submitted by AEP Central and Cities.8 This proceeding was not initiated as a forum for Cities to re-litigate Dr. Goodfriend's expenses. The Commission had previously found that the ALJs correctly detennined that one-half of Dr. Goodfriend's expenses should be disallowed9 because the survey she conducted "was seriously flawed and that conclusions drawn from the data cannot be reasonably supported under current legal 10 standards." The Commission reaffinns this determination, and therefore, the Commission adopts the SOAH ALJs' finding that one-half of Dr. Goodfriend's expenses should be disallowed. In addition, as there are no other outstanding contested issues related to the rate-case expense infonnation submitted in Docket No. 28840 or the additional rate-case expense infonnation 6 See Docket No. 28840, Proposal for Decision at 121-127, 205 (FOF 212) (Jul. 1, 2004). 7 Id at 125. 8 See Open Meeting Tr. at 62 (Jul. 29, 2005). 9 Open Meeting Tr. at 196-198 (January 13, 2005). 10 Docket No. 28840, Proposal for Decision at 125 (Jul. I, 2004). DOCKET NO. 31433 ORDER PAGE4 submitted in this docket, the Commission finds that the rate-case expenses of $2,938,130 for AEP Central and $1,350,299 for Cities are reasonable and necessary. III. The SOAH ALJs' Findings and Conclusions in Docket No. 28840 In the PFD issued on July 1, 2004, in Docket No. 28840, the SOAH ALJs included Finding of Fact Nos. 210 through 216 and Conclusion of Law No. 58 addressing rate case expenses. The SOAH ALJs' findings were issued prior to the updating by AEP Central and Cities of their rate case expenses in their filings described in Finding of Fact No. 15. Thus, in order to reflect the updated factual evidence filed in Docket No. 31433 and certain other corrections described below, the Commission modifies the SOAH ALJs' Finding of Fact Nos. 210 through 216 as follows. Finding of Fact Nos. 22 through 25 of this Order modify the SOAH ALJs' Finding of Fact No. 210 to reflect the updated amounts of rate case expenses found reasonable and necessary for AEP Central after reflecting the disallowance recommended by Staff. Finding of Fact No. 27 of this Order modifies the SOAH ALJs' Finding of Fact No. 211 to reflect the updated amount of Cities' requested rate case expenses. Finding of Fact Nos. 28 and 29 of this Order modify the SOAH ALJs' Finding of Fact No. 212 to reflect the updating of Dr. Goodfriend's portion of Cities' requested rate case expenses. Finding of Fact Nos. 31and32 of this Order adopt the SOAH ALJs' Finding of Fact Nos. 214 and 215. Finding of Fact No. 33 of this Order modifies the SOAH ALJs' Finding of Fact No. 216 to reflect the amounts found reasonable and necessary by the Commission based on the updated information in this proceeding and corrects it to reflect that the rate case expenses will be collected through a three-year surcharge and not through cost of service. Finding of Fact No. 34 of this Order supplements the SOAH ALJs' Finding of Fact No. 256 to reflect the updated amounts for AEP Central's and Cities' rate case expenses found reasonable and necessary by this Order. Finding of Fact No. 35 reflects the Commission's policy decision, in accordance with its decision in Docket No. 30706, 11 that AEP Central not be permitted to recover estimated appeal costs in this proceeding, but that AEP Central be afforded the opportunity to recover in its next rate case any reasonable and necessary expenses for Docket Nos. 28840 and 31433 that it 11 Application of CenterPoint Energy Houston Electric, LLC for a Competition Transition Charge, Docket No. 30706, Order at 28-29, 47 (COL 28) (Jul. 14, 2005). DOCKET NO. 31433 ORDER PAGES subsequently incurs that exceed the amounts found reasonable and necessary by this Order. Finally, Conclusion of Law No. 6 in this Order incorporates the SOAH ALJs' Conclusion of Law No. 58. The Commission adopts the following findings of fact and conclusions of law: IV. Findings of Fact A. Background and Procedural Matters 1. AEP Central is an electric utility providing transmission and distribution (T&D) services in a 44,000 square-mile area of South Texas that includes the portion of Texas from just south of San Antonio to the Mexican border and from Bay City west to Eagle Pass. AEP Central' s service area is located within the Electric Reliability Council of Texas (ERCOT). 2. On November 3, 2003, AEP Central filed an application with the Commission to change its T&D rates. The Commission assigned AEP Central's application to Docket No. 28840. 3. Concurrent with filing its application with the Commission, AEP Central filed a similar petition and statement of intent with each incorporated city in its certificated service area that retains jurisdiction over its retail rates. Eighty-six (86) cities denied AEP Central's petition and statement of intent. AEP Central filed petitions for review of those denials and filed motions to consolidate those petitions for review into Docket No. 28840. 4. On November 4, 2003, the Commission referred AEP Central's application in Docket No. 28840 to SOAH to conduct an evidentiary hearing on the merits and issue a PFD. 5. The following parties intervened and participated in the hearing in Docket No. 28840: Cities; Texas Industrial Energy Consumers (TIEC); CPL Retail Energy (CPL Retail); Coalition of Commercial Ratepayers (CCR); City of Garland, Alliance for Retail Markets (ARM); TXU Business Services (TXU); Texas Legal Services Center and Texas Ratepayers' Organization to Save Energy (TLSCROSE); South Texas Electric Cooperative, Inc. (STEC); State of Texas; Office of Public Utility Counsel (OPC); and Commission Staff (Staff). DOCKET NO. 31433 ORDER PAGE6 6. In Docket No. 28840, AEP Central requested approval of a revenue requirement of $519.9 million, based on an historical test year of July 1, 2002, through June 30, 2003. Of that amount, $426.6 million was for providing retail T&D service (including the portion of the ERCOT-wide transmission costs) and $93.3 million for providing wholesale transmission service. 7. The evidentiary hearing on the merits in Docket No. 28840 was held on March 2 through March 18, 2004. 8. On July 1, 2004, the SOAH ALJs assigned to hear Docket No. 28840 issued their PFD. The PFD contained certain findings with respect to rate case expenses. 9. The Commission issued orders on July 28 and August 25, 2004, remanding portions of Docket No. 28840 to SOAH, none of which involved rate case expenses. 10. On November 16, 2004, the SOAH ALJs issued their Remand PFD in Docket No; 28840. 11. On March 3, 4, and 7, 2005, the Commission held hearings on merger savings and affiliate expenses. 12. On August 15, 2005, the Commission issued its final order in Docket No. 28840. In Ordering Paragraph 5 of that order, the Commission severed the determination of the reasonableness and necessity of rate case expenses into this proceeding, Docket No. 31433. All portions of the evidentiary record in Docket No. 28840 relevant to rate case expenses are part of the evidentiary record in this Docket No. 31433. 13. On August 26, 2005, the presiding officer issued Order No. 1, which required the parties to file evidence of rate case expenses and directed AEP Central and Cities to file supporting detailed documentation for their requested rate case expenses. Order No. 1 also made all parties to Docket No. 28840 parties to this proceeding. DOCKET NO. 31433 ORDER PAGE7 14. On August 29, 2005, Cities requested clarification from the presiding officer regarding the extent of the supporting documentation the Cities were required to submit under Order No.1. 15. On August 30, 2005, Order No. 2: Clarification of Order No. 1, was issued informing Cities that: The entirety of the rate case expenses will be considered in this proceeding. To the extent supporting documentation for expenses prior to September 2004 is in the record of Docket No. 28840, Cities may simply provide the relevant cite to the record. If the supporting documentation for expenses is not in the Docket No. 28840 record, that information should be submitted in this proceeding. 16. On September 9, 2005, AEP Central and Cities filed supporting documentation for their requested rate case expenses, consisting of invoices, timesheets, receipts, etc. On September 16 and October 10, 2005, AEP Central filed supplemental information related to certain of its requested rate case expenses. 17. On September 19, 2005, the presiding officer established a procedural schedule for this docket. In accordance with the procedural schedule, statements of position were due on October 14, 2005, and requests for hearing were due on October 28, 2005. 18. On October 14, 2005, AEP Central, Cities, and Staff filed statements of position. In its statement of position, Staff questioned certain items of AEP Central' s rate case expenses as lacking adequate supporting documentation. in its statement of position, AEP Central stated that the SOAH ALJs had recommended that one:--half of Dr. Goodfriend's expenses be disallowed and noted that Cities' requested rate case expenses included the entire amount billed by Dr. Goodfriend to Cities, and not one-half of that amount. In its statement of position, Cities indicated that they did not contest any of AEP Central' s rate case expenses, but indicated that if Cities' request associated with Dr. Goodfriend's work was contested, then Cities would urge that the standard applied to Dr. Goodfriend be applied to AEP Central' s experts. DOCKET NO. 31433 ORDER PAGES 19. On October 28, 2005, AEP Central filed a motion for ruling on a disputed issue and conditionally requested a hearing seeking a Commission ruling on whether, by severing rate case expenses from Docket No. 28840, it intended to reopen for litigation the issue of Dr. Goodfriend's expenses which had been fully litigated in Docket No. 28840. AEP Central's pleading also included an identification of the portions of the record in Docket No. 28840 that addressed the issue of the quality of Dr. Goodfriend's work and the recovery of her rate case expenses. 20. On December 12, 2005, the presiding officer issued Order No. 4, which requested a clarification regarding a contested issue and directed Staff to file a list of disputed factual . issues and a list of threshold legal and policy issues that must be addressed before this proceeding can be resolved, and permitting AEP Central and Cities to make similar filings. 21. On December 22, 2005, AEP Central and Cities filed their responses to Order No. 4. In its response, AEP Central withdrew its conditional request for a hearing. 22. Based on the filings of the parties set forth in Finding of Fact Nos. 16, 18, 19, and 21, the Commission finds that no factual matters that have not already been fully litigated in Docket No. 28840 are at issue or disputed. The only disputed issue in this proceeding involves the recoverability of one-half of Cities' witness Goodfriend's expenses, which has been subjected to a full contested case evidentiary hearing, briefing, and the issuance by the SOAH ALJs of a PFD in Docket No. 28840. B. AEP Central's Rate Case Expenses 23. Based on its filing of September 9, 2005, as supplemented by its filings of September 16 and October 10, 2005, AEP Central sought recovery of $2,962,734 in recoverable rate case expenses for Docket No. 28840 through June 2005. 24. In its statement of position filed on October 14, 2005, Staff questioned whether $24,604 of AEP Central' s requested rate case expenses were supported by adequate underlying documentation and recommended disallowance of these expenses. DOCKET NO. 31433 ORDER PAGE9 25. In its filing of October 28, 2005, AEP Central indicated that it did not contest Staffs recommendation to disallow $24,604 of AEP Central's requested rate case expenses. 26. AEP Central's reasonable and necessary rate case expenses for Docket No. 28840 as of June 2005 are $2,938,130. C. Cities' Rate Case Expenses 27. In its filing of September 9, 2005, Cities requested rate case expenses for Docket No. 28840 of $1,391,925. This amount consisted of $1,166,925 in expenses actually incurred through July 2005 and $225,000 in estimated expenses including appeals. 28. Cities' actual expenses of $1,166,925 through July 2005 included $83,253 billed by Cities' witness Sarah Goodfriend. 29. The Commission adopts the SOAH ALJs' finding regarding disallowance of one-half of Dr. Goodfriend's expenses from Docket No. 28840 because of the inadequacies in the survey she performed. The record indicates that Dr. Goodfriend has billed the Cities $83,253; therefore a disallowance of one-half of her fees is $41,626. 30. Based on Findings of Fact Nos. 27 through 29, Cities' recoverable rate case expenses are $1,350,299. 31. AEP Central' s proposal to disallow Cities' witness Starnes expenses is not appropriate because the principal rate design issues raised by Cities benefit other rate payers. 32. Cities' rate case expenses are system costs that should be borne by all ratepayers because other ratepayers benefit from the Cities' participation. D. Rate Case Exoense Surcharge 33. Based on Finding of Fact Nos. 26 and 30, the aggregate amount of rate case expenses found reasonable and necessary for AEP Central and Cities are $4,288,429. DOCKET NO. 31433 ORDER PAGElO 34. It is appropriate for AEP Central to surcharge the aggregate rate case expenses found reasonable and necessary in Finding of Fact No. 33 to be collected from all customers over three years. E. Subsequent Rate Case Expenses 35. To the extent AEP Central incurs rate case expenses for Docket Nos. 28840 and 31433 after June 2005, it is reasonable for it to recover such expenses in its next rate case to the extent it demonstrates that such additional expenses are reasonable and necessary. Also, to the extent that Cities incur rate case expenses for Docket Nos. 28840 and 31433 after July 2005 that cause Cities' aggregate rate case expenses to exceed the amount found recoverable by this Order, it is reasonable for AEP Central to recover such expenses in its next rate case to the extent found reasonable and necessary. V. Conclusions of Law 1. AEP Central is an electric utility as defined by §§ 31.002 of the Public Utility Regulatory Act, TEX. UTIL. CODE ANN.§§ 11.001-66.017 (Vernon 1998 & Supp. 2005) (PURA) and is therefore subject to the Commission's jurisdiction under PURA §§ 32.001, 33.051, and 36.102. 2. AEP Central is a T&D utility as defined in PURA § 31.002(19). 3. SOAH had jurisdiction over all matters relating to the conduct of the hearing in Docket No. 28840, including the preparation of a Proposal for Decision pursuant to PURA § 14.053 and TEX. Gov'T CODE ANN.§ 2003.049(b). 4. AEP Central met its burden of proof regarding the amount of its rate case expenses for Docket No. 28840 through June 2005 found reasonable and necessary in Finding of Fact No. 26. DOCKET NO. 31433 ORDER PAGE 11 5. With the exception of the Cities' rate case expenses disallowed in Finding of Fact No. 29, Cities met their burden of proof that their rate case expenses for Docket No. 28840 are reasonable and necessary. 6. Cities are entitled to reimbursement for their rate case expenses as customers, as well as for being regulatory authorities. 7. The evidentiary record in Docket No. 28840 on rate case expenses, including the portion related to the quality of work performed by Dr. Goodfriend underlying her testimony submitted in Docket No. 28840 identified in AEP Central's pleading described in Finding of Fact No. 19, is part of the evidentiary record in this case together with the additional supporting documentation filed by AEP Central and Cities in this proceeding as discussed in Finding of Fact No. 16. 8. No contested issues of fact beyond those that were fully litigated, argued, and heard by the SOAH ALJs in Docket No. 28840 have be.en raised in this proceeding; therefore, there is no need for any further evidentiary hearing on the merits on recoverable rate case expenses in addition to those already held in Docket No. 28840. 9. When the issue of the quality of the work underlying Dr. Goodfriend's testimony in Docket No. 28840 was litigated before and the issue of the recoverability of her rate case expenses was briefed to the SOAH ALJs, Cities had the opportunity to challenge the quality of AEP Central' s experts' substantive work and the recovery of their rate case expenses under the standard applied by the SOAH ALJs to Dr. Goodfriend's expenses. Cities failed to take advantage of that opportunity and no additional evidentiary hearing on the merits is appropriate in this proceeding as to that matter. VI. Ordering Paragraphs In accordance with these findings of fact and conclusions of law, the Commission issues the following Order: DOCKET NO. 31433 ORDER PAGE 12 1. The additional supporting documentation filed by AEP Central and Cities on September 9, 2005, .and by AEP Central on September 16 and October 10, 2005, as discussed in Finding of Fact No. 16 above, is admitted into the evidentiary record of this Docket No. 31433. 2. To the extent provided in this order, the requests by AEP Central and Cities for determination of their reasonable and necessary rate case expenses for Docket No. 28840 are granted. 3. As set forth in Finding of Fact No. 34, AEP Central is authorized to surcharge, over a three- year period, the aggregate rate case expenses for Docket No. 28840 found reasonable and necessary in Finding of Fact No. 33. 4. AEP Central shall file tariff sheets consistent with this Order (compliance tariff) no later than 20 days after receipt of this Order. The Compliance tariff, and all filings related to it, shall be filed in Tariff Control Number 32385 and shall be styled: Compliance Tariff of AEP Texas Central Company Pursuant to Final Order in Docket No. 31433 Severed from Docket No. 28840. The Filing shall include a transmittal letter stating that the tariffs attached are in compliance with this Order, giving the docket number, date of this Order, a list of tariff sheets filed, and any other necessary information. The timetable for review of the compliance tariff shall be established by the Commission's ALJ assigned to the tariff. In the event any sheets are modified or rejected, AEP Central shall file proposed revisions to those sheets in accordance with the Commission's ALJ. All subsequent filings in connection with the compliance tariff (i.e., requests for extensions, textual corrections, revisions) shall be filed in the Tariff Control Number provided above, and styled as set forth above. After issuance of the final order, no further filings other than those pertaining to a motion for rehearing shall be made in this docket. . 5. As set forth in Finding of Fact No. 35, AEP Central may seek to recover in its next rate case expenses in connection with Docket Nos. 28840 and 31433 that it incurs after June 2005 and Cities' rate case expenses incurred in connection with Docket No. 28840 and 31433 that DOCKET NO. 31433 ORDER PAGE 13 exceed the amounts authorized to be recovered herein, to the extent such additional expenses are found reasonable and necessary. 6. 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 herein, are denied. SIGNED AT AUSTIN, TEXAS the c9: