# Entergy Texas, Inc.// Office of Public Utility Counsel and Public Utility Commission of Texas v. Public Utility Commission of Texas and Texas Industrial Energy Consumers// Office of Public Utility Counsel and Entergy Texas, Inc. > Texas Court of Appeals, 3rd District (Austin) · June 2, 2015 URL: https://www.frixlaw.com/law-library/cases/4067257 ## Case - **Court:** Texas Court of Appeals, 3rd District (Austin) - **Decided:** June 2, 2015 - **Precedential status:** Published - **Opinion:** Opinion - **Cited by:** 0 later opinions in the Frix Law Library ## Citator (automated) - No negative treatment found by the automated citator. That is not the same as a confirmation that the case is good law; read the citing cases. - Full citator and citing cases: https://www.frixlaw.com/law-library/cases/4067257 ## Opinion text ACCEPTED 03-14-00735-CV 5514728 THIRD COURT OF APPEALS AUSTIN, TEXAS 6/2/2015 3:48:59 PM JEFFREY D. KYLE CLERK No. 03-14-00735-CV IN THE FILED IN 3rd COURT OF APPEALS THIRD COURT OF APPEALS AUSTIN, TEXAS AT AUSTIN, TEXAS 6/2/2015 3:48:59 PM JEFFREY D. KYLE Entergy Texas, Inc., et al., Clerk Appellants v. Public Utility Commission of Texas, et al., Appellees Appeal from the 353rd Judicial District Court, Travis County, Texas The Honorable John K. Dietz, Judge Presiding ________________________________________________________________ ENTERGY TEXAS, INC.’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. June 2015 ORAL ARGUMENT REQUESTED TABLE OF CONTENTS TABLE OF CONTENTS ........................................................................................... i INDEX OF AUTHORITIES..................................................................................... ii ARGUMENT AND AUTHORITIES ........................................................................1 I.  There is no evidence or legal justification for the Commission’s disallowance of over $11 million associated with ETI’s unrecovered Hurricane Rita reconstruction costs.................................................................1 A.  Nothing in PURA required the Commission to address amortization of the regulatory asset in Docket No. 37744. ..................1 B.  There is no evidence that anyone intended ETI to begin amortizing the regulatory asset upon the settlement of Docket No. 37744. .............................................................................................3 II.  The Commission’s refusal to make any adjustment to ETI’s test-year level of purchased capacity expense is arbitrary and capricious and unsupported by substantial evidence. ..............................................................7 A.  The Commission misapplied the standard for adjustments to test-year expenses. .................................................................................8 B.  The Commission’s refusal to make any adjustment to test-year levels of capacity costs is not supported by substantial evidence. ..............................................................................................11 III.  The Commission’s decision to set ETI’s transmission equalization expense at the test-year level is unsupported by substantial evidence. .........16 CONCLUSION AND PRAYER .............................................................................18 CERTIFICATE OF COMPLIANCE .......................................................................19 CERTIFICATE OF SERVICE ................................................................................20 APPENDIX ..............................................................................................................22 i INDEX OF AUTHORITIES Cases AEP Texas Central Co. v. Public Util. Comm’n of Tex., 286 S.W.3d 450 (Tex. App. – Corpus Christi 2008, pet. denied) .........................4 Bowden v. Phillips Petroleum Co., 247 S.W.3d 690 (Tex. 2008) ..................................................................................8 City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179 (Tex. 1994) ..................................................................................9 Commint Technical Services, Inc. v. Quickel, 314 S.W.3d 646 (Tex. App. – Houston [14th Dist.] 2010, no pet.) ........................4 Freedom Communications, Inc. v. Coronado, 372 S.W.3d 621 (Tex. 2012) ..................................................................................5 Hawkins v. Texas Co., 209 S.W.2d 338 (Tex. 1948) ................................................................................18 Hendee v. Dewhurst, 228 S.W.3d 354 (Tex. App. -- Austin 2007, pet. denied) ......................................5 Katy Intern., Inc. v. Jinchun Jiang, 451 S.W.3d 74 (Tex. App. – Houston [14th Dist.] 2014, pet. requested) .............5 Office of Pub. Util. Counsel v. Public Util. Comm'n, 878 S.W.2d 598 (Tex. 1994) ..................................................................................5 Office of Pub. Util. Counsel v. Texas-New Mexico Power Co., 344 S.W.3d 446 (Tex. App. – Austin 2011, pet. denied) ......................................4 Railroad Comm’n of Tex. v. High Plains Natural Gas Co., 628 S.W.2d 753 (Tex. 1981) .................................................................................9 State of Texas’ Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615 (Tex. App. – Austin 2014, pet. requested) .................................4 Suburban Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358 (Tex. 1983) ....................................................................... 8, 9, 16 Texas Utils. Elec. Co. v. Public Util. Comm’n, 881 S.W.2d 387 (Tex. App. – Austin 1994), rev’d on other grounds, 935 S.W.2d 109 (Tex. 1996) .................................. 15, 18 ii Vickers v. State, No. 06-14-00072-CR, 2015 WL 1882910, *6 n.11 (Tex. App. – Texarkana Apr. 27, 2015, no pet. h.) ................................................5 Woods v. William M. Mercer, Inc., 769 S.W.2d 515 (Tex. 1988) ..................................................................................4 Statutes Tex. Gov’t Code Ann. § 2001.174...................................................................... 8, 18 Tex. Util. Code Ann. § 11.001, et seq. ......................................................................1 Tex. Util. Code Ann. § 11.002 .................................................................................10 Tex. Util. Code Ann. § 36.051 ...................................................................................9 Tex. Util. Code Ann. § 39.459 ...............................................................................2, 3 Tex. Util. Code Ann. § 39.462 ...............................................................................2, 3 Rules 16 Tex. Admin. Code § 25.231 ........................................................................... 9, 10 Tex. R. Civ. P. 94 .......................................................................................................4 Tex. R. Evid. 201 .......................................................................................................5 Administrative Cases Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No. 32907.............................................7 Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 .........................................................5, 6 iii Appellant Entergy Texas, Inc. (“ETI”) respectfully submits this reply to the appellees’ briefs of the Public Utility Commission of Texas (“the Commission” or “PUCT”) and Texas Industrial Energy Consumers (“TIEC”). ARGUMENT AND AUTHORITIES I. There is no evidence or legal justification for the Commission’s disallowance of over $11 million associated with ETI’s unrecovered Hurricane Rita reconstruction costs. ETI challenges the Commission’s decision to allow it to amortize only $15 million of its Hurricane Rita regulatory asset. That is about $11 million less than ETI proved it is entitled to but has not recovered. The Commission, the only party to address this issue in its response brief, does not present any persuasive argument for upholding its decision. A. Nothing in PURA1 required the Commission to address amortization of the regulatory asset in Docket No. 37744. One of the rationales the Commission gave in support of its decision was its view that PURA section 39.459(c) required ETI’s unrecovered Hurricane Rita reconstruction costs to be addressed in a previous case, Docket No. 37744.2 As explained in ETI’s appellant’s brief, section 39.459(c) does not apply to the situation at hand. That provision addresses what should happen when a utility securitizes hurricane reconstruction costs and then recovers them a second time 1 See Tex. Util. Code Ann. § 11.001, et seq. (“Public Utility Regulatory Act” or “PURA”). 2 AR Part I, Binder 5, Item 185 (Proposal for Decision at 15 & 21-22); AR Part I, Binder 7, Item 244 (Order on Rehearing at 1). 1 from an insurance company. See Tex. Util. Code Ann. § 39.459(c). Here, neither of those things happened. A different statute, PURA section 39.462(a), applies in this situation. That provision authorizes a utility to seek unrecovered hurricane reconstruction costs “in its next base rate proceeding or through any other proceeding authorized by Subchapter C, Chapter 36.” Id. § 39.462(a) (emphasis added). It is undisputed that this case is authorized by Chapter 36. The Commission now tacitly acknowledges that section 39.462(a) applies, but still argues that the issue was statutorily required to be addressed in Docket No. 37744.3 The Commission contends that even under section 39.462(a), it was required to address the issue in Docket No. 37744 because that was the “next” base-rate proceeding after ETI knew it would not receive the anticipated insurance proceeds.4 That statute says no such thing. Indeed, section 39.462(a) broadly authorizes the Commission to address the issue in “any” proceeding authorized by Chapter 36. This reflects the legislature’s understanding of the fact that it is often difficult or impossible for a utility to know when multiple, large insurance claims or government grants will be paid in full. Under the plain language of PURA section 39.462(a), the Commission had authority to address the issue in this case. Moreover, the Commission is flat wrong that Docket No. 37744 was the first base rate case after ETI “knew” what insurance proceeds it would recover. It is 3 PUCT’s Appellee’s Brief at 16-17. 4 See id. at 18. 2 true that ETI had not recovered these insurance proceeds when it initiated Docket No. 37744. But it is undisputed that ETI ended up receiving another $5 million in insurance proceeds after Docket No. 37744, and ETI adjusted its regulatory asset to account for this fact.5 Even under the Commission’s erroneous interpretation of PURA sections 39.459(c) and 39.462(a), then, the Commission was not limited to addressing the issue of hurricane reconstruction costs in Docket No. 37744. B. There is no evidence that anyone intended ETI to begin amortizing the regulatory asset upon the settlement of Docket No. 37744. The second rationale the Commission gave for its order was its conclusion that ETI did not disprove that the issue was resolved in Docket No. 37744.6 That was not, however, ETI’s burden. ETI affirmatively established that it had not yet included the unrecovered insurance proceeds in its rate base, or begun recovering them, when it filed this case.7 Intervening parties responded by arguing that ETI should already have either written off or begun amortizing the Hurricane Rita regulatory asset upon the conclusion of Docket No. 37744.8 In other words, intervenors argued that Docket No. 37744 barred ETI from seeking permission to amortize the full amount of the asset in this rate case. Intervenors, not ETI, bore 5 AR Part II, Binder 37, ETI Exh. 46 (Considine Rebuttal at 18 of 55). 6 AR Part I, Binder 5, Item 185 (Proposal for Decision at 22); AR Part I, Binder 7, Item 244 (Order on Rehearing at 1). 7 AR Part II, Binder 32, ETI Exh. 8 (Considine Direct at 20). 8 E.g., AR Part II, Binder 40, Staff Exh. 1 (Givens Direct at 32-35); AR Part II, Binder 8, Cities Exh. 2 (Garrett Direct at 11). 3 the burden of proof on this affirmative defense. E.g., Tex. R. Civ. P. 94; Woods v. William M. Mercer, Inc., 769 S.W.2d 515, 517 (Tex. 1988); Commint Technical Services, Inc. v. Quickel, 314 S.W.3d 646, 651 (Tex. App. – Houston [14th Dist.] 2010, no pet.). Regardless of who bore the burden of proof, the Commission is bound to interpret a settlement and an order adopting it in accordance with the rules of contract interpretation. See AEP Texas Central Co. v. Public Util. Comm’n of Tex., 286 S.W.3d 450, 464 (Tex. App. – Corpus Christi 2008, pet. denied). The Commission cannot use the opportunity to interpret its prior order as a means to amend it. E.g., Office of Public Util. Counsel v. Texas-New Mexico Power Co., 344 S.W.3d 446, 452 (Tex. App. – Austin 2011, pet. denied). Under the rules of contract interpretation, the primary duty of the Commission is to determine and give effect to the parties’ intentions as expressed in the document. AEP Tex. Cent. Co., 286 S.W.3d at 464. The Docket No. 37744 order does not say anything about the Hurricane Rita regulatory asset, and the Commission does not pretend that it does. Nor does the Commission dispute that a utility must have a regulator’s authority to begin recovering a regulatory asset. See, e.g., State of Texas’ Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615, 646 (Tex. App. – Austin 2014, pet. requested) (recovery of regulatory asset is two-step process, the 4 second step being the authorization of a recovery mechanism). The Commission nevertheless argues that the amortization of the Hurricane Rita regulatory asset should have been “considered” approved in Docket No. 37744 because the order in that case was “ambiguous,” and there is substantial evidence that no one in that case disputed that ETI should get to recover the regulatory asset. The Commission is correct that there is evidence in this case that no one in Docket No. 37744 contested ETI’s right to recover the Hurricane Rita regulatory asset at some point in time. However, there was a dispute in Docket No. 37744 about when and how ETI could recover the regulatory asset. Cities’ witness Jacob Pous testified in Docket No. 37744 that ETI should not be able to amortize the regulatory asset over a five-year period, and should credit the amount to its storm reserve instead.9 No witness in this case testified about, much less controverted, that fact. In short, no witness to this case said the parties to Docket No. 37744 agreed that ETI should begin amortizing the regulatory asset when the case was 9 See Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 (Pous Direct at 113). A certified copy of Mr. Pous’s testimony is attached to this brief at Appendix A. ETI does not present this document in support of the truth of its content. ETI presents the document only to establish that it was filed, and the nature of the matter the witness discussed, in the prior docket. This document was filed with the Commission, a state agency. It is publicly available, and its authenticity is readily verifiable. This Court can, therefore, take judicial notice of the document for the limited purpose ETI presents it. Tex. R. Evid. 201(b); Freedom Communications, Inc. v. Coronado, 372 S.W.3d 621, 623 (Tex. 2012); Office of Pub. Util. Counsel v. Public Util. Comm'n, 878 S.W.2d 598, 600 (Tex. 1994); Vickers v. State, No. 06-14-00072-CR, 2015 WL 1882910, *6 n.11 (Tex. App. – Texarkana Apr. 27, 2015, no pet. h.); Katy Intern., Inc. v. Jinchun Jiang, 451 S.W.3d 74, 94 n.20 (Tex. App. – Houston [14th Dist.] 2014, pet. requested); Hendee v. Dewhurst, 228 S.W.3d 354, 377 n.30 (Tex. App. -- Austin 2007, pet. denied). 5 settled. Nevertheless, the Commission concluded in this case that ETI should have done that. There is no testimony supporting the Commission’s conclusion. The only evidence in this case of what the parties intended when they settled Docket No. 37744 is the settlement agreement itself. Though the settlement agreement expressly mentioned several issues in the case, it said nothing about ETI’s request to amortize the Hurricane Rita regulatory asset. The agreement certainly gave no indication that the parties intended ETI to begin recovering the regulatory asset immediately. The agreement did, however, say, “[e]xcept to the extent that the Stipulation expressly governs a Signatory’s rights and obligations for future periods, this Stipulation shall not be binding or precedential upon a Signatory outside this docket, and Signatories retain their rights to pursue relief to which they may be entitled in other proceedings.”10 Despite that language in the agreement, the Commission maintains that the Mother Hubbard clause in the order adopting the settlement supports its decision in this case.11 The order says that “any … requests for general or specific relief, if not expressly granted in this order, are hereby denied.”12 It is undisputed that neither 10 Id. (Aug. 6, 2010 Stipulation and Settlement Agreement at 12) (emphasis added). 11 PUCT’s Appellee’s Brief at 21. 12 Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010, Order at ¶ 15). Public filings in Commission dockets may be accessed at the Commission’s interchange: http://interchange.puc.texas.gov/WebApp/Interchange/application/dbapps/filings/pgSearch.asp The “Control Number” for each case is its docket number. 6 the settlement agreement nor the order expressly granted ETI the authority to begin amortizing the Hurricane Rita regulatory asset.13 In light of this language in the Docket No. 37744 order and the fact that recovery of a regulatory asset requires express agency approval, it would have been unreasonable for ETI to begin amortizing the asset upon the conclusion of Docket No. 37744. The factual basis for the Commission’s contrary conclusion in this case is not supported by substantial evidence. And there is no legal justification – articulated in the Commission’s order or not – supporting what the Commission did here. Because there is no evidence or law supporting the Commission’s decision, it is not entitled to any deference and should be reversed. II. The Commission’s refusal to make any adjustment to ETI’s test-year level of purchased capacity expense is arbitrary and capricious and unsupported by substantial evidence. In its initial brief, ETI challenged the Commission’s refusal to include in rates any of the increase in purchased capacity expense ETI proved it would incur by the time rates went into effect. Neither the Commission nor TIEC presents any 13 The Attorney General makes a cryptic argument on page 21 of its brief, suggesting that ETI cannot logically argue that “only one part of its request could have been approved” in Docket No. 37744. See PUCT’s Appellee’s Brief at 21. ETI does not contend that the Commission approved anything regarding the Hurricane Rita regulatory asset in Docket No. 37744. The Commission approved ETI’s creation of the regulatory asset in Docket No. 32907 when it recognized ETI’s future right to true-up its anticipated insurance recovery. See Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No. 32907 (Dec. 1, 2006, Order at FOF 28). ETI sought approval of a recovery mechanism in Docket No. 37744. ETI’s point here is that the Commission did not even mention the Hurricane Rita regulatory asset, much less approve an amortization schedule for the asset, in its Docket No. 37744 order. 7 logical basis upon which to disallow the entire $30 million increase in expenses at issue. A. The Commission misapplied the standard for adjustments to test-year expenses. The Commission took the view that only ETI’s test-year level of purchased capacity expense should be included in rates because acknowledging known and measurable changes to test-year data is an “exception.”14 ETI challenged that view as contrary to PURA and judicial precedent. In response, the Commission and TIEC point out that the Commission may exercise “discretion” in determining what changes to make to test-year levels of expense. That does not mean, however, that the Commission has carte blanche to do whatever it wants. Even when it exercises discretion, the Commission must adhere to some guiding principles. See, e.g., Tex. Gov’t Code Ann. § 2001.174(2) (agency order reversible for abuse of discretion); Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 696 (Tex. 2008) (failure to adhere to any guiding principles constitutes abuse of discretion). One of those principles is that rates are set prospectively. E.g., Suburban Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358, 366 (Tex. 1983). Another is that a utility is entitled to a reasonable opportunity to recover all of the 14 AR Part I, Binder 7, Item 244 (Order on Rehearing at 1); AR Part I, Binder 5, Item 185 (Proposal for Decision at 108). 8 reasonable and necessary expenses it incurs when the rates are in effect. See Tex. Util. Code Ann. § 36.051; Railroad Comm’n of Tex. v. High Plains Natural Gas Co., 628 S.W.2d 753 (Tex. 1981). PURA provides no support for giving test-year data more weight than rate-year data in the process of setting rates. PURA does not even impose the test-year construct – that is a Commission-made ratemaking convention. Compare Tex. Util. Code Ann. § 36.051 with 16 Tex. Admin. Code § 25.231(a). And the Texas Supreme Court has acknowledged that the goal of the process is to make the test-year data as representative as possible of the cost situation that is apt to prevail in the future, not the past. City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179, 188 (Tex. 1994). Costs that can be anticipated with reasonable (not absolute) certainty should be included. See Suburban Util. Corp., 652 S.W.2d at 362. TIEC and the Commission acknowledge this is the standard. But they argue the Commission’s order should be upheld because ETI could not predict its rate- year costs with surgical precision. That cannot be a basis upon which to disallow the entire adjustment. Without a crystal ball, it is impossible to know future costs to the dollar. The Commission may not disregard compelling evidence of substantial increases to test-year levels of expense simply because there may be some level of uncertainty at the margin. 9 TIEC argues that projections of future expenses should be treated as inherently suspect because there is a risk the projections will end up being too high. TIEC fails to note that placing undue emphasis on test-year data imposes the opposite risk – that rates will end up being too low. The Commission is charged with setting rates that are just and reasonable for both consumers and utilities. Tex. Util. Code Ann. § 11.002(a). Contrary to TIEC’s assertions, ETI does not, in this appeal, seek to overturn the Commission’s test-year approach to ratemaking. See 16 Tex. Admin. Code § 25.231(a). ETI simply seeks to hold the Commission to PURA’s basic guarantee to utilities. To give effect to that guarantee, historical test-year data can only be the starting place for setting rates. Because rates are set on a prospective basis, evidence of known and measurable changes to test-year data must be given at least equal weight to the test-year data itself. It cannot logically be treated with suspicion or as an “exception” that is subject to a heightened proof requirement. The Commission itself acknowledges this principle in other contexts. The Commission made adjustments to other categories of ETI’s test-year expense, even though those adjustments were based upon projections and estimates.15 If the Commission is to allow post-test-year changes based upon projections in one 15 E.g., AR Part I, Binder 5, Item 185 (Proposal for Decision at 68 (short-term asset update), 163- 64 (payroll adjustments), & 182-86 (ad valorem tax rate update)). 10 situation, it must allow them in another. It is an abuse of discretion to apply different standards in materially analogous circumstances. B. The Commission’s refusal to make any adjustment to test- year levels of capacity costs is not supported by substantial evidence. ETI showed that during the time rates would be in effect, it would incur over $38 million annually above its test-year level of purchased capacity expense. ETI showed that by procuring these third-party resources, it would save about $8 million annually in payments related to Entergy system resources. Accordingly, ETI requested the Commission to include the net $30 million increase over its test- year levels of purchased capacity expense in rates. The Commission and TIEC argue the Commission was justified in denying this request for several reasons. First, the Commission says ETI merely “believes” its contracts will be in place during the rate year.16 But ETI proved that all the third-party capacity contracts were executed before the hearing.17 Indeed, one of them went into effect during the test year,18 and another went into effect five months after the test-year end and several months before the hearing in this case.19 16 See PUCT’s Appellee’s Brief at 33. 17 E.g., AR Part IV, Binder 43, Vol. L (5/3/12 Tr. at 1942 & 1959) (Frontier contract); AR Part II, Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25) (SRMPA contract); AR Part II, Binder 35, ETI Exh. 34 (Cooper Direct at 16 of 25) (regarding Calpine contract). 18 AR Part IV, Binder 43, Vol. L (5/3/12 Tr. at 1942 & 1959) (regarding Frontier contract). 19 AR Part II, Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25) (regarding SRMPA contract). 11 The Commission and TIEC also argue that ETI simply “assumed” it would have to pay for all the third-party resources it had contracted for. That is affirmatively debunked by the record. ETI’s expectation that any adjustments for poor performance under the Frontier contract would be minor was based upon its past experience with the Frontier resource.20 ETI also proved that its agreement with SRMPA was for “system capacity.”21 Even if one of SRMPA’s resources were to falter, there is no evidence supporting the conclusion that SRMPA’s entire system might become unavailable. ETI further proved that it had experience with the Calpine resource, and that price deviations under that contract were “very, very small” in ETI’s experience.22 ETI took its historical experience into account when projecting future costs, and did not blindly assume what they would be under these contracts. The Commission and TIEC also contend that there are multiple “offsets” that would negate any additional expense ETI will incur under the new third-party purchased capacity contracts. As ETI pointed out in its appellant’s brief, none of these offsets justifies a complete disallowance of ETI’s entire capital outlay for the contracts at issue. 20 AR Part IV, Binder 43, Vol. F (4/26/12 Tr. at 705). 21 AR Part II, Binder 31, ETI Exh. 3A (SRMPA Power Contract) [Highly Sensitive]. 22 AR Part IV, Binder 42, Vol. L (5/3/12 Tr. at 1942). 12 Both the Commission and TIEC contend that future load growth may offset some of ETI’s increased purchased capacity expense. Even if the Commission could properly consider future load growth in setting base rates, ETI made the additional third-party capacity purchases to serve existing load,23 and existing customers would recoup substantial savings from increased efficiencies and fuel savings that would result from the purchases.24 Moreover, intervenors’ load growth projections would not fully materialize until the rate year,25 but ETI began incurring the additional purchased capacity costs during and shortly after the test year. The prospect of load growth in ETI’s service area cannot logically offset the immediate increase in purchased capacity expense at issue. The Commission and TIEC also attempt to cast doubt upon ETI’s evidence about how much the increased third-party capacity purchases enable ETI to avoid in MSS-1 costs.26 But TIEC’s own witness admitted the inverse relationship between the two categories of cost.27 Indeed, the record establishes that MSS-1 costs reached test-year lows during the last two months of the test year, when the 23 AR Part II, Binder 37 (ETI Exh. 47, Cooper Rebuttal at 5-7); see also AR Part II, Binder 37 (ETI Exh. 57, May Rebuttal at 13-15). 24 AR Part II, Binder 35 (ETI Exh. 34, Cooper Direct at 24 of 25). 25 AR Part IV, Binder 43, Vol. J (5/1/12 Tr. at 1299-1300) [Highly Sensitive]. 26 As explained in ETI’s appellant’s brief, Schedule MSS-1 to the Entergy System Agreement requires the various Entergy operating companies to make and receive payments according to their relative share of total system capacity. See AR Part II, Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5-6). 27 AR Part II, Binder 41, TIEC Exh. 1 (Pollock Direct at 22, Table 1). 13 Frontier contract was stepped up.28 And another intervenor, Cities, adopted ETI’s calculation of rate-year MSS-1 costs.29 Finally, the MSS-430 calculation is not a basis upon which to disallow all of ETI’s increased third-party purchased capacity costs. The Commission itself acknowledged that, save for costs associated with ETI’s contract with its Arkansas affiliate, MSS-4 costs would remain “fairly stable” from the test year to the rate year.31 Regarding the Arkansas contract (referred to by the parties as the Entergy Arkansas, “EAI” or “EA” “WBL” contract), Cities’ and TIEC’s proposed adjustments are not reasonably supported by the record. The evidence shows that although the contract expired after the test year, ETI had extended the contract by the time the hearing took place.32 Additionally, it is not reasonable to conclude that if the Arkansas contract were not in place, ETI would not replace it with another resource, since it is undisputed that ETI needed the capacity.33 In a nutshell, the Commission and TIEC argue that because there is “some uncertainty” in these projections, it was inappropriate to make any adjustment. But 28 See AR Part II, Binder 9, Cities Exh. 6C (Nalepa Direct Attachment KJN-3 at 2) [Highly Sensitive]. 29 AR Part II, Binder 9, Cities Exh. 6C (Nalepa Direct at 17 [Highly Sensitive]). 30 As explained in ETI’s initial brief, Schedule MSS-4 to the Entergy System Agreement contains a formula that sets the price of power purchased from specific units owned by other Entergy operating companies. See AR Part II, Binder 36, ETI Exh. 39 (Cicio Direct at 24-26). 31 AR Part I, Binder 5, Item 185 (Proposal for Decision at 100); AR Part I, Binder 7, Item 244 (Order on Rehearing at 1). 32 AR Part IV, Binder 43, Vol. E (4/26/12 Tr. at 687-88 [Confidential]) . 33 See AR Part II, Binder 37 (ETI Exh. 47, Cooper Rebuttal at 15-16 of 21). 14 this Court long ago rejected the notion that when some of a utility’s proposal is challenged, the entire proposal must be rejected unless the utility itself quantifies the challenged piece. See Texas Utils. Elec. Co. v. Public Util. Comm’n, 881 S.W.2d 387, 404 (Tex. App. – Austin 1994), rev’d on other grounds, 935 S.W.2d 109 (Tex. 1996). This Court recognized that when the evidence conflicts about how much of a proposal to include, it is the Commission’s job to sift through the evidence and make the call. The Commission may not just throw its hands in the air and refuse to address the issue simply because the utility’s evidence is contested or because the issues are complex. See id. at 404-05. TIEC cites the testimony of witnesses who recommended that the Commission adopt a level of purchased capacity expense below the test-year level, and suggests this testimony alone supports the Commission’s decision.34 But each piece of testimony TIEC cites is based upon multiple “offsets” to ETI’s increased level of expense. Each of these proposed offsets are flawed, as explained in ETI’s appellant’s brief and above. Moreover, even assuming arguendo one of the offsets were sustainable, no single offset justifies the entire disallowance. For both these reasons, it is not reasonable to conclude from the evidence in this record that none of ETI’s $30 million increase in third-party capacity costs were known and measurable. The Commission did not even suggest that any single finding justifies 34 See TIEC’s Appellee’s Brief at 33. 15 the entire disallowance, or how much of the disallowance is attributed to each of its findings. Therefore, if this Court determines that any of the Commission’s findings are unsupported by substantial evidence, it must reverse the whole disallowance and remand to the Commission for further consideration. III. The Commission’s decision to set ETI’s transmission equalization expense at the test-year level is unsupported by substantial evidence. ETI challenges the Commission’s decision to set ETI’s MSS-2 (that is, transmission equalization) expense at the test-year level for two reasons. First, the Commission misapplied the “known and measurable” ratemaking standard, as it did in setting ETI’s purchased capacity costs. Second, the Commission’s decision is not supported by substantial evidence. The Commission and TIEC filed responses. They devote their entire argument on this issue to attacking ETI’s evidence supporting its request to include its rate-year level, rather than test-year level, of MSS-2 expense in rates. The issue before the Court, however, is whether there is substantial evidence supporting the Commission’s conclusion that the test-year MSS-2 expense was the level the utility “anticipated with reasonable certainty.” Suburban Util. Corp., 652 S.W.2d at 362. Clearly, this is not the case; there is no evidence that the test year level allowed by the Commission is adequate or representative of the expense the utility will incur when rates are in effect. All the evidence is to the contrary. 16 As ETI noted in its initial brief, no witness testified that the test-year level of expense was a fair or reasonable representation of what ETI would incur under Schedule MSS-2 when these rates would be in effect. Though they proposed different levels of increase, every witness testifying on this issue – including ETI’s, TIEC’s, and Cities’ – recognized that the test-year amount of MSS-2 expense was too small and should be updated based on more recent, actual payment information. 35 Moreover, ETI established that the actual, historical level of MSS-2 expense it incurred, in every month from the end of the test year to the time of the hearing, pointed to a substantially increasing, known and measurable level of expense. 36 TIEC now wholly ignores its own witness’s testimony on this issue, choosing instead to focus exclusively on its criticisms of ETI’s evidence. Even assuming arguendo that there is reasonable disagreement about ETI’s proposed rate-year level of MSS-2 expense, the record conclusively establishes that the test- year level is not adequate. In this circumstance, the Commission may not blindly adhere to its test-year convention. There is literally no evidence to support the Commission’s decision. The Commission is bound to consider all the record evidence and reach a conclusion that is reasonably supported by it. See Hawkins v. Texas Co., 209 35 AR Part IV, Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Part IV, Binder 43, Vol. F (4/27/12 Tr. at 738, 760, 763, 780, & 783-84); AR Part II, Binder 41, TIEC Exh. 1 (Pollock Direct at 32- 33); AR Part II, Binder 8, Cities Exh. 4B (Goins Direct, Errata No. 3 at 9 [Highly Sensitive]); AR Part II, Binder 8, Cities Exh. 4 (Goins Direct at 22). 36 AR Part II, Binder 9, Cities Exh. 29 (Response of ETI to Cities RFI-5-1). 17 S.W.2d 338, 339-40 (Tex. 1948); Texas Utils. Elec. Co., 881 S.W.2d at 404. The APA confirms this principle, requiring a court to reverse the agency if its decision is “not reasonably supported by substantial evidence considering the reliable and probative evidence in the record as a whole.” Tex. Gov’t Code Ann. § 2001.174(2)(E) (emphasis added). Because the Commission’s decision is not supported by any evidence, much less reasonably supported by the evidence, the Court must reverse it. CONCLUSION AND PRAYER For all these reasons, Entergy Texas, Inc. respectfully requests this Court reverse the district court’s judgment insofar as it affirms the Public Utility Commission’s order in the respects discussed above. ETI requests the Court remand the case to the Commission for further proceedings consistent with the Court’s decision. Entergy Texas, Inc. further requests its costs of court and any other relief to which it may show itself justly entitled. 18 Respectfully submitted, /s/ Marnie A. McCormick John F. Williams State Bar No. 21554100 Marnie A. McCormick State Bar No. 00794264 mmccormick@dwmrlaw.com DUGGINS WREN MANN & ROMERO, LLP P. O. Box 1149 Austin, Texas 78767-1149 (512) 744-9300 (512) 744-9399 fax ATTORNEYS FOR APPELLANT ENTERGY TEXAS, INC. CERTIFICATE OF COMPLIANCE I certify that this document contains 4,727 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 19 CERTIFICATE OF SERVICE The undersigned counsel certifies that the foregoing document was electronically filed with the Clerk of the Court using the electronic case filing system of the Court, and that a true and correct copy was served on the following lead counsel for all parties via electronic service on the 2nd day of June, 2015: Elizabeth R. B. Sterling Environmental Protection Division Office of the Attorney General P. O. Box 12548 (MC 066) Austin TX 78711-2548 Counsel for Appellee Public Utility Commission of Texas Rex D. VanMiddlesworth Benjamin Hallmark Thompson Knight LLP 98 San Jacinto Blvd., Ste. 1900 Austin TX 78701 Counsel for Intervenor Texas Industrial Energy Consumers Susan M. Kelley (retired)37 Administrative Law Division Office of the Attorney General P. O. Box 12548 Austin TX 78711-2548 Counsel for Intervenor State Agencies Sara Ferris Office of Public Utility Counsel 1701 N. Congress Ave., Ste. 9-180 P. O. Box 12397 Austin TX 78711-2397 Counsel for Intervenor Office of Public Utility Counsel 37 State Agencies have not yet appeared or designated a new lead counsel in this appeal. 20 Daniel J. Lawton LAWTON LAW FIRM PC 12600 Hill Country Blvd., Ste. R-275 Austin TX 78738 Counsel for Cities of Anahuac, et al. /s/ Marnie A. McCormick Marnie A. McCormick 21 APPENDIX A. Certified copy of Direct Testimony of J. Pous in PUCT Docket No. 37744 22 APPENDIX A SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 37744 'I II APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE INC. FOR AUTHORITY TO CHANGE § OF RATES AND RECONCILE FUEL COSTS § ADMINISTRATIVE HEARINGS Ii DIRECT TESTIMONY AND EXIDBITS OF JACOBPOUS ON BEHALF OF I CERTAIN CITIES SERVED BY ENTERGY TEXAS, INC. CBRTIPIBD TO BS ATRUE AND CORRSCT COPY OF THE OIUOINAL ON FH..E WITH THE PUBLIC UTILITY COMMISSION OF TEXAS JUNE9,2010 c~~'~. :*t:3';• Diversified Utility Consultants Inc. 1912 West Anderson Lane, Suite 202 Austin, TX 78757 Record copY ·- UL \ 3 'l.0\6 Cities Exhibit , 'K.'f ·-· ,I ' TABLE OF CONTENTS SECTION I: INTRODUCTION .................................................................................................... 1 SECTION II: DEPRECIATION ..................................................................................................... 7 1. General ........................................................................................................................................ 7 2. Production Life ........................................................................................................................... 11 A. General ................................................................................................................................... 11 B. Basis for Retirement Dates ..................................................................................................... 14 C. Recommendation .................................................................................................................... 21 3. Production Interim Retirements .................................................................................................. 22 4. Production Net Salvage ............................................................................................................... 26 5. Mass Property Life .................................................................................................................. 38 A. Introduction ........................................................................................................................... 38 B. Account Specific Adjustments .............................................................................................. 43 6. Mass Property Net Salvage ......................................................................................................... 71 7. ELG vs. ALG Calculation Procedure ......................................................................................... 76 8. Remaining Life Method .............................................................................................................. 86 SECTION III: FULLY ACCRUED DEPRECIATION ................................................................. 89 SECTION IV: SGSF CAPITAL RECOVERY .............................................................................. 93 SECTIONV: STORM INSURANCE RESERVE ...................................................................... 102 1. General .................................................................................................................................... I 02 2. Storm Reserve Deficit ............................................................................................................. 105 3. Target Reserve ........................................................................................................................ 114 4. Annual Expected Losses ......................................................................................................... 117 I 5. Minimum Storm Reserve Threshold ....................................................................................... 120 SECTION VI: CASH WORKING CAPITAL ................................................................................. 123 I I 1. Introduction ............................................................................................................................. 123 2. General .................................................................................................................................... 125 3. Revenue Lag ............................................................................................................................. 127 A. Meter Reading To Billing ................................................................................................... 127 B. Billing-To-Payment Revenue Lag ...................................................................................... 130 C. Customer Float .................................................................................................................... 135 4. Expense Leads .......................................................................................................................... 136 A. Payroll .................................................................................................................................. 136 B. FAS 106 .............................................................................................................................. 139 C. Entergy Services Inc. ("ESI") Expense Lead ..................................................................... 141 D. Other O&M Expense Lead ................................................................................................. 142 SECTION VII: RIVER BEND DECOMMISSIONING REVENUE REQUIREMENT .............. 144 SECTION VIII: RIVER BEND DEPRECIATION RATES ........................................................... 149 2 ACRONYMS: 2008 Study 2008 Gannett Fleming Depreciation Study AICPA American Institute of Certified Public Accountants ALG Average Life Group APFD Accumulated Provision for Depreciation ASL Average Service Life CIS Consumer Information Systems Company Entergy Texas, Inc. Commission Public Utility Commission of Texas CPI Consumer Price Index ewe Cash Working Capital DUCI Diversified Utility Consultants, Inc EIA U.S. Energy Information Administration EAi Entergy Arkansas, Inc. EGSL Entergy Gulf States Louisiana ELG Equal Life Group ESI Entergy Services, Inc. ETI Entergy Texas, Inc. FERC Federal Energy Regulatory Commission FPL Florida Power & Light Company FPSC Florida Public Service Commission MPSC Michigan Public Service Commission NARUC National Association of Regulatory Utility Commissioners NIMB "not in my backyard" syndrome NPC Nevada Power Company NPSC Nevada Public Service Commission NRC Nuclear Regulatory Commission O&M Operation & Maintenance occ Oklahoma Corporation Commission OLT Observed Life Table PSO Public Service of Oklahoma PUC Public Utility Commission of Texas RCT Railroad Commission of Texas 1 Reserve Accumulated Provision for Depreciation SGSF Spindletop Gas Storage Facility SGT Sabine Gas Transportation Company SRP Strategic Resource Plan SWEPCO Southwest Electric Power Company USOA FERC Uniform System of Accounts 2 Docket No. 37744 APPLICATION OF ENTERGY TEXAS § BEFORE THE INC. FOR AUTHORITY TO CHANGE § PUBLIC UTILITY RATES & RECONCILE FUEL COSTS § COMMISSION OF TEXAS SECTION I: INTRODUCTION 1 Q. PLEASE STATE YOUR NAME AND BUSINESS? 2 A. My name is Jacob Pous and my business address is 1912 W. Anderson Lane, Suite 202, 3 Austin, Texas 78757. 4 5 Q. WHAT IS YOUR OCCUPATION? 6 A. I am a principal in the firm of Diversified Utility Consultants, Inc. ("DUCI"). A copy of 7 my qualifications appears as Appendix A. 8 9 Q. HAVE YOU PREVIOUSLY TESTIFIED IN PUBLIC UTILITY PROCEEDINGS? 10 A. Yes. Appendix A also includes a list of proceedings in which I have previously presented 11 testimony. In addition, I have been involved in numerous utility rate proceedings that 12 resulted in settlements before testimony was filed. In total, I have participated in well 13 over 400 utility rate proceedings in the United States and Canada. 14 15 Q. WHAT IS YOUR PROFESSIONAL BACKGROUND? 16 A. I am a registered professional engineer. I am registered to practice as a Professional 17 Engineer in the State of Texas, as well as numerous other states. 18 19 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? 20 A. I am testifying on behalf of the cities of Anahuac, Beaumont, Bridge City, Cleveland, 21 Conroe, Houston, Huntsville, Montgomery, Navasota, Oak Ridge North, Pine Forest, 22 Pinehurst, Port Arthur, Port Neches, Groves, Nederland, Orange, Rose City, Shenandoah, I 1 I 1 Silsbee, Sour Lake, Splendora, Vidor, and West Orange ("Cities") served by the Entergy 2 Texas, Inc. ("Company" or "ETI"). 3 4 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 5 A. The purpose of my testimony is to address certain adjustments that are required to ETI's 6 requested rate increase filed before the Public Utility Commission of Texas 7 ("Commission" or "PUC"). I have provided Cities' witness Mr. Garrett with my 8 recommendations in order that they will be incorporated into the Cities' total revenue 9 requirement presentation. 10 11 Q. PLEASE BRIEFLY SUMMARIZE YOUR TESTIMONY. 12 A. The following is a brief summary of each of the major areas I address herein. 13 14 • Production Plant Life Spans. The Company proposes to retire almost all of its 15 gas-fired generation on June 30, 2025, for purposes of calculating depreciation 16 rates in this case as set forth in the 2008 Gannett Fleming depreciation study 17 ("2008 Study"). The proposed retirement year is earlier than and inconsistent with 18 the Company's internal planning for system resources. The Company's proposed 19 depreciation life spans assumes a retirement date that is also artificially short in 20 comparison to the life expectancy by the industry as well as the Company's own 21 resource planning division. I recommend establishing minimum life spans for the 22 Company's gas-fired generating facilities at the later of the year 2029 or when 23 such units reach 65 years of age. The standalone impact of this recommendation is 24 a reduction in depreciation expense of $11. 7 million based on plant in service as 25 of December 31, 2008. 26 27 • Interim Retirements. In spite of this Commission's previous rulings and 28 precedent regarding exclusion of interim retirements in the calculation of 29 production plant depreciation rates, the Company still proposes interim 30 retirements in its calculation. The Company's witness, Mr. Spanos attempts to 31 distinguish the Commission precedent by relying on an incorrect premise that the 32 Company's interim retirement analysis is based on a historical perspective, and 33 the Commission's precedent is applicable to a future perspective. This is a 34 distinction without a difference, because the Company applies the result of its 35 historical calculations to projected future results. Therefore, the Company's 36 witness's attempt to distinguish the Company's request from previous 37 Commission decisions is incorrect. The impact of upholding the Commission's 38 long standing precedent against interim retirements results in an approximate $4.6 39 million reduction in depreciation expense based on plant as of December 31, 40 2008. 2 1 2 • Production Plant Net Salvage. The Company proposes negative net salvage 3 values ranging from a negative 15% to a negative 32% for its gas and coal-fired 4 generations. The Company's coal-fired proposal isbased on an undocumented, 5 unsupported and inappropriate regression analysis associated with a database for 6 which the Company's depreciation witness has no first-hand knowledge. The 7 Company does not have a regression or any mathematical model to estimate net 8 salvage for gas-fired generation, but rather assumes it is approximately 80% of 9 the coal-fired value. Therefore, assuming the 80% factor to be correct, any 10 inaccuracies in the coal regression analysis would carry over to the Company's 11 projected net salvage for gas-fired generation. As a second step to the Company's 12 unsupported net salvage analysis, Mr. Spanos escalates the estimated demolition 13 costs as of the end of 2008 into the future for as many as 35 years and 14 recommends s that current customers pay with current dollars for future inflated 15 costs. These aspects of the Company's analysis are neither credible nor 16 reasonable. Therefore, in consideration of significant increases in scrap metal 17 prices that have occurred in the last 5 years and the potential sale of used 18 equipment, a zero (0) level of net salvage for production plant is recommended. 19 On a standalone basis this recommendation results in a reduction of 20 approximately $11. 7 million in depreciation expense based on plant as of 21 December 31, 2008. 22 23 • Mass Propertv Life Analysis. There are numerous problems with the Company's 24 proposed life-curve combination for the various mass property accounts 25 (transmission, distribution and general plant). First and foremost, the Company's 26 life analysis includes the impact of hurricane activity as typical, ongoing events. 27 This has resulted in certain accounts having life expectations shorter than 28 basically all other utilities in the industry. In addition, the Company's consultant 29 recognizes that there is a "significant portion" of the survivor curve to which the 30 curve-fitting process should be geared; however he has failed to properly 31 implement such criteria. Finally, the Company has failed to provide reasonable or 32 adequate support for its various positions. Modifications to 16 of the Company's 33 proposals results in a standalone impact of a $11.1 million reduction to annual 34 depreciation expense based on plant as of December 31, 2008. 35 I 36 37 • Mass Property Net Salvage. The Company's analysis relies only on the most recent 5 years of data. This compares to a 16-year database employed by the same consultant in the current El Paso Electric Company case before this Commission. l 38 39 40 Without any indication in the testimony, depreciation study or workpapers, is the fact that the limited five years of data is not even maintained by account, yet it is I 41 42 presented by account based on an initially unidentified data manipulation. Another fatal flaw in the Company's proposals is that there are the effects of several major hurricanes reflected in the 5-year historical database. Thus, the data 43 ! 44 45 46 relied upon by the Company to propose net salvage parameters are significantly skewed to more negative levels than would reasonably be expected. Given the significant problems with the Company's presentation and database in this case, I 3 I 1 retaining the existing levels of net salvage by account is recommended. On a 2 standalone basis this recommendation results in a $10.6 million reduction in 3 annual depreciation expense based on plant in service as of December 31, 2008. 4 5 • Calculation Procedure. The Company proposes to use the Equal Life Group 6 ("ELG") calculation procedure. The ELG procedure is not a conservative capital 7 recovery method and in fact represents an accelerated procedure when compared 8 to the industry standard Average Life Group ("ALO") calculation procedure. The 9 ELG procedure is inaccurate in all instances, except in the improbable scenario 10 that future annual retirements for up to 100 years into the future can be precisely 11 estimated. In reality, ETI cannot predict future annual retirement levels with any 12 degree of accuracy, even for as little as a 5-year period. Relying on the ALO 13 procedure, a straight line, non-accelerated procedure, results in a standalone 14 reduction to annual depreciation expense of $19.3 million based on plant as of 15 December 31, 2009. 16 17 • Combined Impact of Depreciation Adjustments. The combined impact of the 18 various depreciation adjustments is not simply the summation of the individual 19 standalone impacts. If life, net salvage, or calculation procedure proposals are 20 modified within the same account, they are interactive with each other. As set 21 forth on Schedule (JP-1 ), the combined impact of the various adjustments results 22 in a $57 million reduction in depreciation expense based on plant in service as of 23 December 31, 2008. 24 25 • Fully Accrued Depreciation. The Company admits that it unilaterally changed 26 the Commission approved depreciation rates when it ceased booking depreciation 27 expense for three accounts. The Company does not have the authority to 28 unilaterally change a depreciation rate previously approved by the Commission. 29 Reversal of the Company's inappropriate actions results in a $6.2 million decrease 30 in rate base and a $1.5 million credit amortization expense associated with a four- 31 year amortization period. 32 33 • Spindletop Gas Storage Facilitv l"SGSF"). Since the Company's last fully 34 litigated rate proceeding, the Company has exercised an option to purchase the 35 SGSF facilities for $1. Due to the unique situation of ownership, operation and 36 cost recovery, customers have significantly overpaid depreciation expense and are 37 now entitled to appropriate net salvage treatment and correction of the 38 intergenerational inequity that has transpired. Amortizing the excess depreciation 39 reserve over a 4-year period and recognition of Company-established net salvage 40 expectations results in a $5.5 million reduction to revenue requirements 41 associated with this unique investment. However, given Cities' witness Mr. 42 Nalepa's recommendation relating to the SGSF, only $1.2 million of my 43 recommendation associated with the recognition of net salvage is required, when 44 Mr. Nalepa's position is adopted. 45 4 1 • Storm Insurance Reserve. The Company has overstated revenue requirements in 2 the calculation of its insurance reserve request. The Company performs a flawed 3 Monte Carlo simulation. The Company has skewed its results to the high side 4 based on the inclusion of inappropriate costs and charges to the insurance reserve. 5 ETI also inappropriately attempts to segregate certain hurricane securitization cost 6 from the reserve. Removing certain inappropriate charges to the Company's 7 insurance reserve and performing a more realistic projection of future storm cost 8 accruals results in a $7. 7 million reduction to the Company's storm reserve annual 9 accrual and a $45.9 million reduction to rate base. In addition, I recommend an IO increase in the current $50,000 storm insurance threshold limit to $500,000. 11 12 • Cash Working Capital ("CWC"). The Company overstates and incorrectly 13 calculates the Company's CWC requirements. In particular, the Company relies 14 on an inconsistent implementation of service period between revenues and 15 expenses. There are numerous other flaws associated with the Company's 16 approach to CWC that require correction. Based on my various recommendations, 17 the standalone impact of the corrected lead-lag analysis for the measurement of 18 ewe requirements would result in an incremental $43.7 million reduction to rate 19 base and an approximate corresponding $5. 7 million reduction to revenue 20 requirements. 21 22 • River Bend Decommissioning. The Company seeks approval from this 23 Commission for its proposed level of decommissioning expense associated with 24 the River Bend plant that is now owned by ETI's Louisiana affiliate Entergy Gulf 25 States Louisiana ("EGSL"). Cities' witness Mr. Brazell testifies that the 26 Commission does not have the authority to set a decommissioning revenue 27 requirement for River Bend given EGSL' s ownership of the plant. The 28 Company's proposal is based on a 40-year life span for River Bend, rather than 29 the more appropriate and realistic 60-year life expectancy. Therefore, if the 30 Commission were to determine the proper decommissioning revenue requirement 31 for Texas retail customers, I recommend that a 60-year life span be employed. In 32 addition, the beginning balances in the decommissioning funds are understated in 33 the Company's presentation and would need to be corrected. The standalone 34 impact of these adjustments eliminates the need for Texas retail customers to 35 contribute any additional amounts to the decommissioning trust funds. Therefore, l 36 37 my recommendation results in a $2.8 million reduction to proposed annual decommissioning revenue requirements. 38 39 • River Bend Depreciation. Cities' witness Mr. Brazell presents the position that 40 the Commission does not have the authority to set depreciation rates for River 41 Bend. However, the Company has requested that the Commission do just that. 42 Unfortunately, the Company's presentation reflects a 40-year service life for 43 River Bend. It should be noted that the Company relies on a 60-year life for 44 River Bend in the Louisiana jurisdiction and agreed to a 60-year life in Docket 45 No. 34800, a settled proceeding. While the Company has not yet received 46 permission from the Nuclear Regulatory Commission (''NRC") for such license 5 1 extension, it must be noted that not a single license application for the 20-year life 2 extension has been denied by the NRC. Therefore, if the Commission does elect 3 to establish a depreciation rate for River Bend, it should do so based on the 20- 4 year life extension and with no interim retirements reflected therein. 5 6 Q. IS THERE A CONCERN THAT NEEDS TO BE ADDRESSED AT THE 7 BEGINNING OF YOUR TESTIMONY? 8 A. Yes, in the area of depreciation and capital recovery a utility can present aggressive, 9 middle of the road, or conservative parameters given the subjectivity required in 10 performing any future depreciation or capital recovery estimate. After review of the 11 Company's depreciation presentation, it is clear that the Company's position in this case 12 is one of the most aggressive presentations realistically possible. The Company's 13 approach results in an extremely excessive level of depreciation expense, rapid return of 14 capital investment to shareholders, which in my estimation, is unreasonable and an 15 unnecessary burden for current customers. 16 17 Q. DO THE PROPOSED DEPRECIATION PARAMETERS CONTINUE THE 18 CORPORATE PLAN THAT PUSHES AGGRESSIVE DEPRECIATION 19 PRACTICES? 20 A. Yes. While utilities have become more sophisticated in the last several decades when it 21 comes to spelling out their corporate plans, this Company continues its predecessor's 22 Corporate Plan, which under the heading of Long-Range Corporate Objectives, stated the 23 following: "Push accounting/depreciation judgments aggressively where possible." 1 24 (Emphasis added). 25 26 Q. CAN YOU PROVIDE SPECIFIC EXAMPLES THAT DEMONSTRATE ETl'S 27 CONTINUATION OF THE PREVIOUSLY STATED AGGRESSIVE 28 DEPRECIATION PRACTICES? 29 A. Yes. First and foremost is the Company's decision to utilize the ELG calculation 30 procedure. Reliance on the ELG procedure in light of identifiable "anomalies" that result 31 from the analyses of the underlying data is flawed and can no longer be relied upon to 1 Gulf States Utilities Corporate Plan 1980-1984 item l(c). 6 I predict with some degree of certainty how mortality patterns might look in the future. 2 The anomalies in the analyses are due, at least in part, to problems with the data, 3 including potential problems associated with the jurisdictional separation of ETI and 4 EGSL. Indeed, the combination of the underlying data problems with the fact that the 5 ELG procedure is the most accelerated book depreciation calculation procedure that can 6 be proposed in a rate proceeding, can only result in a magnified distortion of the capital 7 recovery process compared to the industry standard ALG calculation procedure. 8 9 Next, in the area of production plant net salvage, Mr. Spanos not only relied upon an I0 unsubstantiated regression analysis that produces excessively negative values, but then 11 proposed a unique escalation calculation. The Company, through Mr. Spanos' testimony, 12 proposes to charge current customers, who would have to pay with current dollars, for 13 costs that have been escalated, without discounting costs back to the present, for as many 14 as 35 years into the future. Such approach is illogical and unrealistic. 15 16 While there are other actions taken by Mr. Spanos that further push his and the 17 Company's aggressive depreciation goals, the above examples more than establish the 18 nature of the Company's presentation. 19 SECTION II: DEPRECIATION 20 1. General 21 I 22 23 Q. A. WHAT IS DEPRECIATION? There are two commonly cited definitions of depreciation. The first comes from the I 24 25 Federal Energy Regulatory Commission's ("FERC") Uniform System of Accounts ("USOA"): 2 l 26 'Depreciation', as applied to depreciable plant, means the loss in service 27 value not restored by current maintenance, incurred in connection with I 28 the consumption or prospective retirement of electric plant in the course 2 Title 18 Code of Federal Regulations Part 101. 7 1 of service from causes which are known to be in current operation and 2 against which the utility is not protected by insurance. Among the causes 3 to be given consideration are wear and tear, decay, action of the 4 elements, inadequacy, obsolescence, changes in the art, changes in 5 demand and requirements of public authorities. 6 The second definition, from the American Institute of Certified Public Accountants 7 ("AICPA"), is similar: 8 Depreciation accounting is a system of accounting which aims to 9 distribute the cost or other basic value of tangible capital assets, less 10 salvage (if any) over the estimated useful life of the unit (which may be a 11 group of assets) in a systematic and rational manner. It is a process of 12 a/location, not of valuation. Depreciation for the year is a portion of the 13 total charge under such a system that is allocated to the year. Although 14 the allocation may properly take into account occurrences during the 15 year, it is not intended to be a measurement of the effect of all such 16 occurrences. 17 Q. WHAT ARE THE TWO GENERAL FORMULAS USED IN DETE RMINING 18 DEPRECIATION RATES? 19 A. The whole life and the remaining life technique are the most commonly used formulas. 20 The whole life technique is as follows: 3 Depreciation Rate (%) = [ Original Cost - Net Salvage Average Service Life Original Cost J 21 The remaining life technique for calculating depreciation rates is as follows: 22 ~ J Original Cost - Reserve - Net Salvage Depreoiation Rate (%) [ Remaining Life Original Cost 3 A theoretical depreciation reserve calculation is developed and compared to the actual accumulated provision for depreciation in conjunction with the whole life technique. If the differential is significant, an amortization of the differential for some period of time may be recommended. 8 1 The two formulas should equal each other when the difference between the theoretical 2 reserve and the actual Accumulated Provision for Depreciation ("APFD" or "reserve") 3 are recovered over the remaining life of the investment under the whole life formula. 4 5 Q. ARE THERE ADDITIONAL CONSIDERATIONS IN DEPRECIATION BEYOND 6 THE DEFINITIONS? 7 A. Yes. The definitions provide only a general outline of the overall utility depreciation 8 concept. In order to arrive at a depreciation-related revenue requirement in a rate 9 proceeding, a depreciation system must be established. 10 11 Q. WHAT IS A DEPRECIATION SYSTEM? 12 A. A depreciation system constitutes the method, procedure, and technique employed in the 13 development of depreciation rates. 14 15 Q. BRIEFLY DESCRIBE WHAT IS MEANT BY "METHOD". 16 A. Method identifies whether a straight-line, liberalized, compound interest, or other type of 17 calculation is being performed. The straight-line method is normally employed for utility 18 depreciation proceedings. 19 20 Q. BRIEFLY DESCRIBE WHAT IS MEANT BY "PROCEDURE". 21 A. Procedure identifies a calculation approach or grouping. For example, procedures can 22 reflect the grouping of only a single item, items by vintage (year of addition), items by 23 broad group or total grouping, and equal life groupings. The vast majority of utilities and I 24 25 regulatory authorities use the ALG procedure. I 26 27 Q. A. PLEASE BRIEFLY DESCRIBE WHAT IS MEANT BY "TECHNIQUES". There are two main categories of techniques with various sub-groupings: the whole life I 28 29 technique and the remaining life technique. The whole life technique simply reflects calculation of a depreciation rate based on the whole life (e.g., a ten-year life would I 30 31 imply a ten percent depreciation rate over the life of a plant). The remaining life technique recognizes that depreciation is a forecast or estimation process that is never 9 1 precisely accurate and requires true-ups in order to recover only 100% of what a utility is 2 entitled to over the entire life of the investment. Therefore, as time passes, the remaining 3 life technique attempts to recover the remaining unrecovered balance over the remaining 4 life or other period. Most utilities rely on a remaining life technique in utility rate matters. 5 6 Q. DO THE METHODS, PROCEDURES, AND TECHNIQUES INTERACT WITH 7 ONE ANOTHER? 8 A. Yes. Different depreciation rates will result depending on what combination of method, 9 procedure and technique is employed. Differences will occur even when beginning with 10 the same average service life and net salvage values. 11 12 Q. WHAT IS NET SALVAGE? 13 A. Net salvage is the value obtained from retired property (the gross salvage) less the cost of 14 removal. Net salvage can be either positive in cases where gross salvage exceeds cost of 15 removal, or negative in cases where cost of removal is greater than gross salvage. 16 17 Q. HOW DOES NET SALVAGE IMPACT THE CALCULATION OF 18 DEPRECIATION? 19 A. The intent of the depreciation process is to allow the Company to recover 100% of 20 investment less net salvage. Therefore, if net salvage is a positive 10%, then the utility 21 should only recover 90% of its investment through annual depreciation charges, under the 22 theory that it will recover the remaining 10% through net salvage at the time the asset 23 retires (e.g., 90% + 10% = 100%). Alternatively, if net salvage is a negative 10%, then 24 the utility should be allowed to recover 110% of its investment through annual 25 depreciation charges so that the negative 10% net salvage that is expected to occur at the 26 end of the property's life will still leave the utility whole (e.g., 110% - 10% = 100%). 27 28 Q. WHAT ARE THE KEY ELEMENTS OF THE DEPRECIATION FORMULA AT 29 ISSUE IN TIDS PROCEEDING? 30 A. All parameters in the previously noted formula are at issue. The establishment of life and 31 net salvage parameters are a function of the analyses performed, the interpretation of the 10 1 data, the judgment and experience of the analys~ and other relevant information. In 2 addition, the remaining life calculation is at issue given that Mr. Spanos of Gannett 3 Fleming performs a different remaining life calculation than every other utility that does 4 not retain Gannett Fleming that I have dealt with over the past 37 years, including this 5 Company. This remaining life calculation produces theoretically impossible results. 6 Finally, the calculation procedure is a major issue in this case, as ETI does not rely on the 7 industry standard ALG procedure. 8 2. Production Life 9 A. General 10 11 Q. WHAT IS THE ISSUE IN TlllS PORTION OF YOUR TESTIMONY? 12 A. This portion of my testimony addresses the appropriate life spans for the Company's 13 various generating units. In particular, I will address what appears to be a practice of 14 understating the life span for generating units. I recommend longer life spans for the 15 Company's gas-fired generating units. 16 17 Q. WHAT IS A LIFE SPAN FOR A GENERATING UNIT? 18 A. A life span for a generating unit sets the period during which it is expected to be in 19 service prior to being retired. For example, if a generating unit was placed into service on 20 January 1, 1980 and had a 60-year estimated life span it would have a projected 21 retirement date of December 31, 2040. It should be noted that a generating unit that is 22 placed in peaking or standby service is still in service and not retired. I 23 24 Q. PLEASE EXPLAIN THE SIGNIFICANCE OF SETTING AN APPROPRIATE ~ 25 LIFESPAN. 26 A. In determining the depreciation rate, and thus depreciation expense for a generating unit, I 27 it is necessary to establish the period over which customers are expected to receive 28 benefits and in return pay for such benefits. This process complies with the standard f 29 regulatory "matching principle." As previously noted, the depreciation formula includes I 11 I 1 the original cost less net salvage less the APFD, all divided by the remaining life. Thus, if 2 the life spans, and the related remaining life, are set at too short a period, current 3 customers overpay and vice versa. Failure to set a proper estimated retirement date for a 4 generating unit creates intergenerational inequities and fails to comply with the 5 "matching principle" of ratemaking. 6 7 Q. ARE THE RETIREMENT DATES FOR GENERATING UNITS KNOWN WITH 8 CERTAINTY? 9 A. Not for most units. Even for nuclear units that must operate within the period of a license 10 granted by the NRC, we now know that the initial estimate of a 40-year life span has been 11 or will be expanded to 60-years. Indeed, in ETI's last case, Docket No. 34800, the life 12 span for River Bend was extended for ratemaking purposes to 60 years. 4 13 14 Q. WHEN SETTING THE LIFE SPAN FOR A GENERATING UNIT, IS IT 15 APPROPRIATE TO LIMIT THE TIME FRAME TO THE INITIAL ESTIMATED 16 PERIOD CORRESPONDING TO WHEN MAJOR CAPITAL ADDITIONS MAY 17 BE REQUIRED IN ORDER TO KEEP THE UNIT IN SERVICE? 18 A. No, even though ETI and its depreciation consultant, Mr. Spanos, attempt to rely on such 19 a concept to artificially limit the current estimate of life span for units. Indeed, it is 20 questionable whether even the Company really believes such less than credible argument 21 given the sizeable capital additions it had to make in the early stages of service life for its 22 gas fired units. 5 In recognition of these sizeable capital additions that were necessary to 23 keep the units operating, ETI did not attempt to limit the life spans in its earlier 24 depreciation studies to the date of the expected capital additions. 4 PUC Docket No. 34800 Final Order FOF 34. s Exhibit JJS-1pages209-252. 12 1 Q. WHY IS IT INAPPROPRIATE TO ARTIFICIALLY LIMIT THE LIFE SPAN OF 2 A GENERATING UNIT BASED ON UNCERTAINTY AS TO WHETHER 3 FUTURE CAPITAL ADDITIONS WILL BE MADE? 4 A. It is inappropriate to implement such depreciation judgment because it assumes that 5 utilities will act differently in the future than they have acted in the past without the 6 benefit of specific factors that would warrant such a change. Generating units are very 7 capital-intensive items. Economic theory recognizes that it is normally expected that 8 capital expenditures and normal maintenance expense will not only be made, but 9 encouraged as necessary, to keep a large capital intensive facility in operation for as long 10 as economically practical. This has been the Company's practice as it applies to actual 11 operation of its units. 12 13 An analogy would be associated with the purchase of a home. A new home can easily be 14 expected to last well over 50 years. However, a major capital expenditure for a new roof 15 may be required after 15 to 20 years. No reasonable person would set the life expectancy 16 of the house at 20 years because the decision has not been made regarding an expected 17 major expenditure 20 years in the future. The same can be said about limiting the 18 expected initial life expectancy of a house to even 30 or 40 years when the second 19 replacement of a roof can be expected. The issue becomes at what point would one 20 expect external forces such as a change in character of the neighborhood or other events 21 to change, for it to warrant the abandonment of the house. As long as the best use of the 22 house is as a dwelling and it is economically cost effective to make repairs and 23 replacements, the initial life should not be set artificially short due to potential 24 uncertainties surrounding future major capital additions. I 25 I 26 27 Q. DOES THE COMPANY'S PRODUCTION PLANT DEPRECIATION EXPENSE REPRESENT A SIGNIFICANT REVENUE REQUIREMENT? I 28 29 A. Yes. The Company's 2008 Study identifies over $783 million of investment and proposes $28.4 million in depreciation expense for annual Steam Production plant (Accounts 310- 316). 6 This level of depreciation expense is unnecessary and only arises as a result of the l 30 6 2008 Study at Exhibit JJS-1 page 52. I 13 I Company's witness's aggressive "depreciation judgment" for reflecting life spans, 2 corresponding interim retirements, and net salvage values. 3 B. Basis for Retirement Dates 4 5 Q. WHAT TESTIMONY DID THE COMPANY SPECIFICALLY PROVIDE IN 6 SUPPORT OF THE PROPOSED LIFE SPANS FOR ITS VARIOUS 7 GENERATING UNITS? 8 A. The Company provided the testimony of Mr. Spanos. The entire basis for this significant 9 parameter is set forth at pages 19 and 20 of Mr. Spanos' direct testimony where he states: 10 11 The bases for the probable retirement years are life spans for each facility 12 that are based on judgment and incorporate consideration of the age, use. 13 size. nature of construction. management outlook, and typical life spans 14 experienced and used by other electric utilities for similar facilities. Many 15 of the life spans result in probable retirement years that are many years in 16 the future, but included as part of ETI' s resource plan. As a result, the 17 retirements of these facilities are not yet subject to specific management 18 plans. At the appropriate time, detailed studies of the economics of 19 rehabilitation and continued use or retirement of the facility will be 20 performed and the results incorporated in the estimation of the facility's 21 life span. (Emphasis added). 22 23 Q. DID THE COMPANY ADD ANY ADDITIONAL INFORMATION REGARDING 24 THE BASIS FOR THE LIFE SPANS OF ITS UNITS IN THE 2008 25 DEPRECIATION STUDY? 26 A. While the 2008 Study added the following statements, such verbiage fails to provide any 27 additional meaningful basis for the Company's proposed life spans: 28 29 The life span estimates for power generating stations were the result of 30 considering experienced life spans of similar generating units, the age of 31 surviving units, general operating characteristics of the units, major 32 refurbishing, and discussion with management personnel concerning the 33 probable long-term outlook for the units. Final decisions as to date of 34 retirement will be determined by management on a unit by unit basis. 7 35 (Emphasis added). 7 2008 Study at Exhibit JJS-1 page 35. 14 1 Q. WHAT SPECIFIC ITEM OF INFORMATION HAS THE COMPANY 2 PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE 3 LIFE SPANS FOR ITS GENERATING UNITS REFLECTING 4 "CONSIDERATION OF THE AGE" OR "USE, SIZE, NATURE OF 5 CONSTRUCTION" OF ITS UNITS? 6 A. The Company has provided no information that would support its proposal for a life span 7 as short as 46 years for Sabine 5. In fact, Sabine Units 1 and 2, which are much smaller 8 and dispatched less than Sabine 5, have already reached ages in excess of 46 years. Thus, 9 judgment in conjunction with consideration of age or physical characteristics of the units 10 should have caused the Company to propose longer life spans than it has. 11 12 Q. WHAT SPECIFIC ITEM OF INFORMATION HAS THE COMPANY 13 PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE 14 LIFE SPANS FOR ITS GENERATING UNITS REFLECTING "MANAGEMENT 15 OUTLOOK"? 16 A. The Company has provided no information that would support its proposals. In fact, the 17 timing horizon of the Company's Strategic Resource Plan ("SRP") is through 2028. 8 The 18 SRP planning horizon exceeds the retirement dates for all of the Company's gas-fired 19 units, yet such plan relies on the continued operation of all such units to meet future 20 loads. Thus, even the Company's current management "outlook" refutes the judgment 21 employed by Mr. Spanos in the 2008 Study. 22 23 Q. WHAT SPECIFIC ITEM OF INFORMATION HAS THE COMPANY I 24 25 PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE LIFE SPANS FOR ITS GENERATING UNITS REFLECTING "TYPICAL LIFE ~ 26 SPANS EXPERIENCED AND USED BY OTHER UTILITIES OF SIMILAR 27 FACILITIES"? I 28 29 A. The Company has provided no information. However, through discovery, it was determined that Gannett Fleming has supported a range of life spans for gas-fired units I 30 that is so wide that it would allow for a selection of about any value, even ones 8 Response to Rose City 1-36 Attachments. 15 l approaching 70 years. I submit that Gannett Fleming's life span range for gas-fired units 2 is so large that it defies any credibility that might have been assigned to it in the 3 "judgmental" process claimed by Mr. Spanos. 4 5 Q. DOES MR. SPANOS' TESTIMONY PROVIDE SUFFICIENT EXPLANATION 6 AND JUSTIFICATION TO SUPPORT THE COMPANY'S PROPOSED LIFE 7 SPANS FOR ITS GENERATING FACILITIES? 8 A. No. 9 10 Q. DID THE COMPANY PROVIDE ANY ADDITIONAL INFORMATION JN 11 RESPONSE TO DISCOVERY? 12 A. Yes. Mr. Spanos provided his site visit notes that reference limited additional information 13 such as: 14 15 • System maintenance good; 16 • Control upgrades; 17 • Monthly vibration program, performance tests; and 18 • Boiler exam and maintenance every year. 9 19 20 Q. DO THESE ADDITIONAL STATEMENTS CONTAINED IN MR. SPANOS' SITE 21 VISIT NOTES PROVIDE SUFFICIENT SUPPORT FOR THE COMPANY'S 22 LIFE SPAN PROPOSALS? 23 A. No. These statements represent the type of statements one would expect relating to a 24 dynamic situation requiring decisions whether to retire units or continue to expend funds 25 to permit continued operation. In fact, it is quite clear from these comments and other 26 information in the 2008 Study that the Company has historically decided, and currently is 27 deciding, to make necessary capital expenditures to keep its units in operation long after 28 the claimed initial design life. The Company has faced the decision whether to retire 29 these units or spend funds to keep them in operating condition beyond initial expectations 30 and in each instance has decided that it is economically appropriate and efficient to do 31 what all other utilities have been doing: maximize the life of a capital-intensive asset. 9 Response to Rose City 1-15 Attachment. 16 1 There is more support for longer life spans in Mr. Spanos' notes than there is for the 2 artificially short life spans being proposed. 3 4 Q. DID MR. SPANOS PROVIDE ANY ADDITIONAL INFORMATION 5 REGARDING ms PROPOSED LIFE SPANS DURING ms DEPOSITION? 6 A. Yes. Mr. Spanos stated that the life spans corresponded with the best estimate of the 7 likelihood of assets being either taken out of service (i.e. retired), or the date of expected 8 major capital additions in the future made to change the functionality of the asset. 10 He 9 also admits that the proposed retirement in his study does not necessarily relate to when 10 the units would be shut down. 11 These two statements taken together default to a position 11 that the probable retirement dates in Mr. Spanos' study are the unsubstantiated date Mr. 12 Spanos assumes the Company may make major capital additions to change the 13 functionality of the units. 14 15 Q. IS THERE ANYTHING IN THE USOA THAT DEFINES OR TIES THE 16 SERVICE PERIOD FOR A GENERATING UNIT TO AN ASSUMED DATE 17 WHEN A UTILITY MIGHT MAKE A MAJOR CAPITAL ADDITION THAT 18 CHANGES THE FUNCTIONALITY OF AN ASSET? 19 A. Absolutely not. 20 21 Q. DID MR. SPANOS OR THE COMPANY PROVIDE A SINGLE DOCUMENT 22 THAT DEMONSTRATES THE PROPOSED RETIREMENT DATES ARE THE 23 COMPANY'S BEST ESTIMATE OF WHEN A UNIT WILL RETIRE? I 24 25 A. No. In fact, as previously discussed, the documents presented by the Company now demonstrate that assumed retirements prior to 2029 are not the current best estimate of ~ 26 the Company. ~ I 10 Deposition of Mr. Spanos on April 20, 2010 at TR 39. Id. I II 17 ! 1 Q. DID MR. SPANOS PROVIDE A SINGLE DOCUMENT OR ITEM OF 2 EVIDENCE THAT IT IS APPROPRIATE TO TIE THE PROPOSED 3 RETIREMENT DATE TO A CONCEPT OF WHEN MAJOR CAPITAL 4 EXPENDITURES MIGHT OCCUR? 5 A. No, Mr. Spanos' concept is a backdoor approach to recognizing interim additions, 6 something the PUC and other regulators do not permit. 7 8 Q. WHAT ARE INTERIM ADDITIONS? 9 A. Interim additions are theoretical future dollars of investment or capital additions in plant 10 to be added to existing facility of the Company. Such additions are not the dollars of 11 investment currently in service. Rather, they are .estimated dollars for replacement of 12 certain existing facilities or for additions of new facilities to an existing generating 13 facility in the future. 14 15 Q. ARE INTERIM ADDITIONS APPROPRIATE FOR DEPRECIATION 16 PURPOSES? 17 A. No. Interim additions are inappropriate since they reflect the estimation of potential 18 additions to plant-in-service that currently do not exist and are not used and useful in 19 providing service. Interim additions may never actually occur or may occur at a much 20 different date or amount than initially assumed. 21 22 Q. IN THE RATEMAKING PROCESS, ARE INTERIM ADDITIONS EVER 23 APPROPRIATE FOR DEPRECIATION PURPOSES? 24 A. No. Interim additions are appropriate only after they occur. Once such expenditures 25 occur, and the plant becomes used and useful in providing service, it is appropriate to 26 incorporate the plant investment into a depreciation study. Under this approach, the 27 Company is not deprived of a return of its investments associated with interim additions. 28 Moreover, customers are not inappropriately charged for unknown plant that is not used 29 and useful in providing service to them at the time the depreciation rates are developed. 18 1 Q. WHAT SOURCE SUPPORTS YOUR POSITION THAT ESTIMATED INTERIM 2 ADDITIONS SHOULD NOT BE REFLECTED IN THE DEPRECIATION 3 CALCULATION? 4 A. The National Association of Regulatory Utility Commissioners (''NARUC") 1968 5 publication entitled Public Utility Depreciation Practices describes, on pages 133 and 6 134, how interim additions are treated. It states the following: 7 Appropriate computations must be made for such interim retirements, but 8 interim additions are not considered in the depreciation computation until 9 they are actually made. 10 It is possible to estimate the probable future retirements and additions to a 11 particular piece ofproperty and thus arrive at a single depreciation rate 12 applicable over the entire life of the property. This is an unsatisfactory 13 practice inasmuch as considerable speculations would be required to 14 make such an estimate on future additions. In any event. this is not 15 necessary inasmuch as the depreciation accrual can be adjusted in future 16 years as additions are made. (Emphasis added). 17 18 The 1996 NARUC depreciation publication reaffirms this concept. 12 19 20 Q. HAS THE FERC RENDERED A DECISION ON THE CONCEPT OF 21 INTERIM ADDITIONS? 22 A. Yes. The FERC reviewed and ruled on this issue in its Opinion No. 165, a 23 Commonwealth Edison Company case. 13 In that case, Commonwealth Edison had 24 proposed taking into account budgeted future interim additions and stated that without the 25 inclusion of the budgeted interim additions, there would be a violation of the matching I 26 27 principle (i.e. revenues collected corresponding to the expenses incurred). In Opinion No. 165, the FERC clearly rejected recognition of interim additions: I 28 29 ... we reject its [Edison 'sj claim that this will leave some costs unrecovered after the plant is retired. Such a result might occur if 30 Commonwealth would fail to adjust its depreciation rates from time to I 31 32 time, taking into account up-to-date information on changes in plant balances, estimated remaining life, salvage and removal cost experience, 33 and accumulated provision for depreciation to date. However, I 12 Page 142 states" ... interim additions are not considered in the depreciation base or rate until they occur." 13 23 FERC paragraph 61,219 (1983) 19 1 Commonwealth not only is free to make such adjustments to its 2 depreciation rates, but is obligated to do so to assure that as near as 3 possible the service value of electric plant is fully recovered during its 4 useful life. For all these reasons, we find no basis to approve 5 Commonwealth's depreciation methodology. 14 6 7 Q. IS THERE A NEED TO SPECULATE ON THE COMPANY'S FUTURE 8 INTERIM ADDITIONS? 9 A. No. The Company will have the opportunity to recover actual additions to plant from 10 customers once they occur. 11 12 Q. ARE OTHER UTILITIES FACED WITH THE SAME CONCERNS RELATING 13 TO THE DECISION TO REPAIR OR REPLACE WORN OR BROKEN 14 COMPONENTS VERSUS RETIRE A UNIT? 15 A. Yes, and the trend in the industry has been to project even longer life spans. In fact, in a 16 recent case here in Texas, Southwest Electric Power Company ("SWEPCO") filed for life 17 spans longer than ETI has for comparable units. 15 A listing of comparable size and age of 18 generating units between SWEPCO and ETI, along with the life spans filed by both 19 utilities is set forth in the table below: 20 21 COMPARABLE UNITS Size Year Life Size Year Life ETIUnit (MW) Installed Span SWEPCOUnit 0:: Q) a. :::> (f) 70 60 0.5 8.5 16.5 24.5 32.5 40.5 48.5 4.5 12.5 20.5 28.5 36.5 44.5 52.5 AGE (YEARS) Actual 52R2.5 __..,_ 45R2.5 I In addition, the Company's historical data reflects retirement activity associated with 2 recent hurricanes, thus resulting in an artificially short life indication even based on the 3 Company's actuarial analysis. Next, a review of Mr. Spanos' industry database indicates 4 that a longer ASL is warranted than the 45-year value he proposed. In fact, the mean, 5 median and mode for his industry database all exceed 45 years, even when taking into 6 account some unusually low values associated with cooperatives or old studies reflected 7 in that database. 64 Mr. Spanos' notes also support something longer than a 45-year ASL. 8 For example, Mr. Spanos' notes associated with substations specifically state "about 50 64 Response to Rose City 1-1 7 Attachment. 46 I years. " 65 Indeed, the notes further identify the Company has a policy of cradle to grave 2 accounting for its transformers, which should have indicated a longer ASL compared to 3 the industry average since many utilities actually retire transformers when they move 4 such equipment from one location to another. In addition, while Mr. Spanos' notes 5 indicate that there is an expectation for a shorter lives in the future for transformers, this 6 is an argument that has been utilized in the industry for the past 20 or 30 years, yet the 7 industry has demonstrated increasing life expectancy for substation equipment as more 8 empirical data has been obtained. Therefore, the 52-year ASL is more indicative of the 9 Company's actual experience, better reflects industry expectations, and is more 10 representative of the type of equipment in the account. 11 12 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 13 A. My recommendation of a 52-year ASL on a standalone basis results in a $1,462,347 14 reduction to depreciation expense based on plant in service as of December 31, 2008. 15 16 Account354 17 18 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 354 - 19 TRANSMISSION TOWERS? 20 A. The Company proposes a 50-S4 life-curve combination. 66 21 22 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 23 A. This is an account where the historical data is not relied upon and Mr. Spanos reverts to I 24 25 his generalized statement referring to judgment and other information. 26 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 27 A. No. I recommend a 63-S4 life-curve combination. I I 65 Response to Rose City 1-15 Addendum page 46. 66 Exhibit JJS-1 page 52. 47 1 Q. WHAT IS THE BASIS FOR YOUR RECOMMENDATION? 2 A. First, while the historical data provides an extremely short "stub curve", it does provide 3 an indication for a long ASL given the very limited level of retirement activity that has 4 transpired during over 50 years of data. 67 In addition, Mr. Spanos' industry database 5 indicates a mean, median and mode of 63, 65 and 65 years, respectively. 68 Indeed, the 6 industry data that would have formed possibly a major portion of Mr. Spanos' 7 'judgment" indicates that the use of a 50-year or lower ASL is very limited. Therefore, 8 all indications of available data indicate that a value in the mid 60-year range is by far 9 superior to the Company's proposed 50-year ASL. Moreover, the Company proposed a 10 55-year ASL for Account 355 - Transmission Poles. On a predominant basis, the 11 industry recognizes that transmission towers have longer expected ASLs than do 12 transmission poles. In this case, Mr. Spanos also failed to take this relationship into his 13 judgmental decision making process. 14 15 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 16 A. My recommendation of a 63-year ASL on a standalone basis results in a $110,162 17 reduction to depreciation expense based on plant as of December 31, 2008. 18 19 Account 355 20 21 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 355 - 22 TRANSMISSION POLES AND FIXTURES? 23 A. The Company proposes a 55-R3 life-curve combination. 69 24 25 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 26 A. This is another account where Mr. Spanos claims to have relied on the statistical actuarial 27 results. 70 67 Exhibit JJS-1pages99 and 100. 68 Response to Rose City 1-17 Attachment. 69 Exhibit JJS-1page52. 70 Exhibit JJS-1 page 33. 48 1 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 2 A. No. The Company's proposal is artificially short; therefore, I recommend a 59-R2.5 life- 3 curve combination. 4 5 Q. WHAT IS THE BASIS FOR YOUR RECOMMENDATION? 6 A. As shown in the graph below, my recommendation results in a better fit to the OLT in the 7 significant portion of the curve that Mr. Spanos referenced in his testimony. Indeed, Mr. 8 Spanos sacrificed a better fitting relationship during periods beginning around age 8 years 9 in order to strive for a better match during the age intervals of approximately 25 years 10 through 35 years. The problem with Mr. Spanos' election to discount the earlier portion 11 of the curve in an effort to match a later portion of the curve sacrifices exposures in the 12 $40-$70 million range for better fitting exposures in the $15-$40 million range. 71 As can 13 be seen in the graph be]ow, my recommendation is a superior fit during the first 14 approximate 24 years of age. I 71 Exhibit JJS-1pages104-105. 49 ENTERGY TEXAS 355 - TRANSMISSION POLES AND FIXlURES (1954) 100 90 en a::: 0 > - c:: Q) .... (.) ~ Q) 0... ::::> en 80 70 0.5 8.5 16.5 24.5 32 .5 40.5 48.5 4.5 12.5 20.5 28.5 36.5 44.5 52.5 AGE (YEARS) Actual 59R2. 5 __..._ 55R3 1 In addition, Mr. Spanos' notes indicate that new poles are steel and concrete, thus 2 indicating a longer life expectancy in the future than reflected in the historical data, 3 which reflects a higher level of wood poles. While Mr. Spanos reflected such information 4 in his notes, he apparently failed to take that into consideration in his undocumented 5 decision making process. 72 Otherwise, he would have proposed a longer ASL. Thus, from 6 a curve-fitting process, and taking into account the limited additional information 7 provided by the Company, a longer ASL than the 55-year life proposed by the Company 8 is warranted. Analysis of historical data and supplemental information better supports a 9 59-year ASL. 72 Response to Rose City 1-15 Addendum at page 46. 50 I 1 2 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 3 A. My recommendation for a 59-year ASL on a standalone basis results in a $1,080,733 4 reduction to depreciation expense based on plant in service as of December 31, 2008. 5 6 Account 356 7 8 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 356 - 9 TRANSMISSION OVERHEAD CONDUCTORS? 10 A. The Company proposes a 53-R2.5 life-curve combination. 73 11 12 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 13 A. For this account, the Company relies on Mr. Spanos' claim relating to a good to excellent 14 indication from the statistical analyses. 74 I 15 16 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? I 17 A. No. The Company's proposal understates the realistic ASL for this account. Therefore, I 18 recommend a 55-year ASL with a corresponding R2.5 Iowa Survivor Curve. As shown in 19 the graph below, both Mr. Spanos' proposal and my recommendation are both good fits 20 of the data for approximately the first 27 years of age. At that point the Company's 21 proposal begins to deviate from the OLT until approximately 35 years of age and 22 understates the expected ASL. Thus, both curves are good fits through the most 23 significant portion of the curve, but the longer ASL continues the good fit through most I 24 25 of the remaining portion of the OLT including portions of the curve that are still significant. Another consideration for a somewhat longer ASL is that to the extent any I 26 27 retirement activity associated with major hurricanes that occurred in recent periods is reflected in the Company's data, it would understate the expected ASL for the remaining l 28 29 investment. Therefore, a modest increase from what the Company has proposed in the expected ASL is warranted at this time. 73 Exhibit JJS-1 page 52. 74 Id., at page 33. 51 ENTERGY TEXAS 356 - TRANSMISSION OVERHEAD CONDUCTORS AND DEVICES (1954) 100 90 C/) a: 0 ...c: > Q) ,_ 0 80 > a: Q) a.. ::> C/) 70 60 0.5 8.5 16.5 24.5 32.5 40.5 48.5 4.5 12.5 20.5 28 .5 36 .5 44.5 52.5 AGE (YEARS) Actual __..._ 55R2. 5 -6--- 53R2. 5 1 Q. WHAT IS THE IMP ACT OF YOUR RECOMMENDATION? 2 A. My recommendation for a 55-year ASL results in a $210,829 reduction to the Company' s 3 annual depreciation expense based on plant in service as ofDecember 31, 2008. 4 Accounf 360 5 6 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 360 - 7 DISTRIBUTION LAND RIGHTS? 8 A. The Company proposes a 55-R4 life-curve combination. 75 75 Exhibit JJS-1 page 51. 52 I Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 2 A. Given that there have been no retirement activity reflected in the Company's historical 3 database, this is an account where the Company relied on judgment and other undefined 4 parameters. 5 6 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 7 A. No. The same situation as discussed for Account 350 - Transmission Land Rights also 8 pertains to Distribution Land Rights. The Company's selection would have land rights 9 retiring long before the end of a single life cycle is reached for various other distribution 10 accounts. Thus, on its face, the Company's proposal is illogical. Therefore, I recommend 11 a 85-R4 life-curve combination, taking into account land rights must exist for at least one 12 complete life cycle relating to the investment that resides upon it. As time passes this 13 estimate will have to be expanded in recognition that retirements will not occur as 14 additional new plant is placed on the same land rights and that new investment must also 15 complete its life cycle. 16 17 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 18 A. My recommendation for an 85-year ASL results in a $120,195 reduction in depreciation 19 expense based on plant as of December 31, 2008. 20 21 Account 362 22 23 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 362 - I 24 25 A. DISTRIBUTION STATION EQUIPMENT? The Company proposes a 40-Rl.5 life-curve combination. 76 I 26 27 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? I 28 29 A. This is an account where the Company relied on what appeared to be a good to excellent statistical indication from its statistical analysis of historical data. 77 76 Exhibit JJS-1page53. 77 Id., at page 34. 53 1 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 2 A. No. The Company's proposed ASL is too short for the investment in this account. 3 Therefore, I am recommending a 47-Rl life-curve combination. 4 5 Q. WHAT IS THE BASIS FOR YOUR RECOMMENDATION? 6 A. A review of the historical OLT identifies two significant retirement periods that appear to 7 be out of line. In particular, the Company experienced its second highest retirement level 8 during the age interval of zero (0) to 0.5 year. 78 It is unusual to have such significant 9 levels of infant mortality in comparison to older aged equipment. Indeed, the vast IO majority of this infant mortality incurred in 1954. 79 No other infant mortality of this 11 magnitude has transpired in the subsequent 54 years. Therefore, proper judgment should 12 have recognized this event as an outlier and normalized it in the database. The reality is 13 that utilities, absent unusual events, are not expected to purchase and install equipment 14 that is expected to fail immediately upon installation to any great extent. Thus, the 15 Company's historical OLT reflects an artificial reduction at an early time frame given 16 that such data is being used as a predictive tool for future expectations. 17 The largest level of retirement activity during any age interval occurred beginning at age 18 interval 6.5 years. 80 This annual level of retirement activity is approximately ten times the 19 level of retirement activity in the age intervals immediately preceding or following. 20 Again, this is the type of activity that should have caused an analyst to question the 21 validity of the resulting OLT as a basis for projecting future expectation for the remaining 22 investment. Indeed, this single age bracket yielded the highest retirement ratio through 23 the first 70 years of age.81 The impact of this single age bracket produced an atypical and 24 noticeable decline in the OLT as set forth in the graph in the Company's depreciation 25 study. 82 Events of this magnitude warrant further investigation, yet Mr. Spanos' 26 testimony, exhibits, workpapers and site visit notes make no reference to any specifics 27 regarding this retirement activity. Based upon further investigation it has been determined 78 Exhibit JJS-1 page 126. 79 Response to Rose City 13-7. 80 Exhibit JJS-1page126. 81 Id., at pages 126-127. 82 Id., at page 125. 54 I I that $4.8 million of the $5.4 million was a retirement during age interval 6.5 years and 2 relevant to a 8MVA stored magnetic energy superconductor unit located at a substation. 3 The Company could not provide any support for why a retirement of this magnitude for 4 this type of equipment is expected to reoccur on a similar basis in the future. 83 Therefore, 5 the impact of what is a single, but large, unusual event should have been normalized in 6 the Company's analysis. Indeed, Mr. Spanos, who claims constant reliance on judgment, 7 apparently failed to even recognize that his own database of other utilities would have 8 indicated that his proposed 40-year ASL for this account was well below the mean, 9 median or mode for his industry range. 84 This discrepancy between ETI and the industry 10 should have resulted in this transaction being adjusted prior to the curve fitting process 11 had proper judgment been employed. 12 13 As set forth in the graph below, I have normalized only the outlier at the 6.5 age 14 interval. 85 As can be seen, my recommended 46-SO life-curve combination is a superior 15 or equal fit to all data points when compared to Mr. Spanos' proposal. Moreover, my 16 recommendation better matches Mr. Spanos' industry data and is consistent with the 17 cradle to grave type accounting employed by the Company for transformers and other 18 major equipment at substations, as identified in Mr. Spanos' site visit notes. 86 My 19 recommendation is conservative given the fact that the curve matching process still 20 incorporates atypical hurricane activity that should have also been normalized. I I I 83 Response to Rose City 1-2 13-18. 84 Response to Rose City 1-16 Attachment even prior to the elimination of obvious outliers in Mr. Spanos' own database. ' as Reflects 1979-2008 Experience band to address infant mortality issue. 86 Response to Rose City 1-15 Addendwn at pages 46 and 48. 55 ENTERGY TEXAS 362 - DISTRIBUTION STATION EQUIPMENT (Normafized) 100 90 en g- a:: 80 c:: Q) 0 > a:: a. ~ Q) ::::> 70 en 60 I 50 0.5 8.5 16.5 24.5 32.5 40.5 48.5 56.5 64.5 4.5 12.5 20.5 28 .5 36.5 44.5 52.5 60.5 AGE (YEARS) Actual 46R1.5 __..__ 40R1.5 1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 2 A. My recommended 46-year ASL results in a $783,405 reduction to annual depreciation 3 expense based on plant as of December 31, 2008. Account 365 4 5 I 6 7 Q. WHAT DOES THE DISTRIBUTION OVERHEAD CONDUCTORS? COMPANY PROPOSE FOR ACCOUNT 365 - I 8 A. The Company proposes a 36-R0.5 life-curve combination. 87 1 87 Exhibit JJS-1page53. 56 I 2 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 3 A. This is an account where the Company relied heavily on the results of its statistical 4 analysis. 88 5 6 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 7 A. No. The Company's proposal is artificially short. Therefore, I recommend a 39-S-0.5 life- 8 curve combination. The Company's historical data included $2.8 million of unusual 9 retirement activity in the age interval 0.5 that occurred in 2008, the year in which 10 Hurricane Ike hit. 89 The retirement activity at age intervals 0.5 is significantly greater 11 than any other time frame and is atypical in nature. Therefore, at a minimum, the OLT 12 would need to be normalized for such activity. As shown in the graph below, my life- 13 curve combination is a better match to the historical data minimally for the first 30 years, 14 and then again beginning at approximately 44 years of age. If the remaining retirements 15 associated with recent hurricane activity were also removed from the data, it would raise 16 the OLT and make my recommendation even a better fit than set forth in the graph 17 below. I I I ' 88 89 Id., at page 34. Response to Rose City 13-11. 57 ENTERGY TEXAS 365- DISTRIBUTION OVERHEAD CONDUCTORS & DEVICES (Normalized) 100 :-.. 90 ~~ ~ 80 ~ 70 ~~ Cl) 0:: ~ ~ .., .+J 0 cQ) 60 > e 6; ::::> Cl) Q) a.. 50 40 30 ' ..... ~ ~ ~ 20 ~~ a_ ~ 10 111 111 111 111 Ill 111 Ill 111 111 111 111 111 111 111 ~~ JUI 111 111 111 0.5 8.5 16.5 24.5 32.5 40 .5 48.5 56 .5 64.5 4.5 12.5 20.5 28.5 36.5 44.5 52.5 60.5 AGE (YEARS) I Actual - - - 398-0.5 ___._ 36R0.5 I 1 Other considerations supporting a longer ASL are the fact that the only item of 2 information referenced by Mr. Spanos in his site notes was that if poles go down, 3 conductors may not be damaged and thus still in use. 90 All else equal, this would imply 4 that an ASL for conductors should be approximately as long as poles, if not longer. It 5 should be noted that my 39-year ASL recommended for conductors is one year shorter 6 than what Mr. Spanos has recommended for poles. Finally, a review of Mr. Spanos' 7 industry data would indicate that even a 39-year ASL is on the shorter side of life 8 expectancy. Thus, in conjunction with my life recommendation, the Commission should 9 also order the Company to perform a detailed analysis to normalize the impacts of major 1O hurricanes that occurred in the 2005 through 2008 era for use in the next depreciation 90 Response to Rose City 1-15 Addendum at page 49. 58 1 study. Overall, my recommended 39-year ASL is conservative, considering actual 2 historical data even before normalization for all hurricane activity. 3 4 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 5 A. My recommendation for 39-year ASL results in a $1,103,876 reduction in depreciation 6 expense based on plant as of December 31, 2008. 7 8 Account 366 9 IO Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 366 - 11 DISTRIBUTION UNDERGROUND CONDUIT? 12 A. The Company proposes a 50-R2 life-curve combination. 91 13 14 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 15 A. This is an account where the Company did not rely on the statistical analysis it 16 performed, but rather relied on unidentified judgment and other factors. 92 17 18 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 19 A. No. First, it must be noted that the existing ASL for this account is 60 years. Thus, the 20 Company is proposing a 10-year reduction based on undefined judgment. A review of the 21 data indicates unusually high levels of retirement activity at low age intervals, without 22 any explanation. 93 Substantial amounts of these early age retirements are associated with 23 underground plastic conduit and pads for transformers. These are not the type of I 24 25 investments that one would normally anticipate retiring at early ages, absent unusual circumstances. Moreover, industry experience would indicate that even a 50-year ASL is 26 artificially short. Indeed, Mr. Spanos' industry data, which is skewed with several very 94 27 short lives, still yields mean, median and mode values of approximately 55-60 years. 28 There is no logical explanation or documentation presented by the Company that 91 Exhibit JJS-1 page 53. 92 Id., at page 34. 93 Response to Rose City 13-12 through 13-15. 94 Response to Rose City 1-17. 59 1 warrants a reduction from the existing 60-R3 life-curve combination. Therefore, I 2 recommend retention of the existing ASL, which is more in line with the type of 3 investment reflected in this account. 4 5 Q. WHAT IS THE IMP ACT OF YOUR RECOMMENDATION? 6 A. My recommended 60-year ASL results in a $182,339 reduction to depreciation expense 7 based on plant as of December 31, 2008. 8 9 Account 368 10 11 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 368 - 12 DISTRIBUTION LINE TRANSFORMERS? 13 A. The Company proposes a 29-SO life-curve combination.95 14 15 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 16 A. For this account the Company relied on what it believed to be a good or excellent 17 statistical fit for the historical data. 96 18 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 19 A. No. The Company's proposal results in one of the shortest ASLs for any utility in the 20 industry. Therefore, at a minimum, I recommend increasing the ASL to 32 years with a 21 corresponding L0.5 Iowa Survivor Curve. 22 23 Q. WHAT IS THE BASIS FOR YOUR RECOMMENDATION? 24 A. First, a 31-L0.5 life-curve combination represents as good a fit to the OLT as does the 25 Company's proposal. Indeed, given the type of investment and other considerations, a 31- 26 L0.5 life-curve combination is a more realistic expectation for the investment in this 27 account. However, some of the other items of information exist that require some 28 additional level of increase in ASL. Those other items of information are the existing 29 ASL, the impact of hurricane related retirements, and industry information. The existing 95 Exhibit JJS-1 page 53. 96 Id., at page 34. 60 1 ASL for this account is 39 years, thus the Company is proposing a value 10 years shorter 2 than the existing level. Even if this was a reasonable prediction, which it is not, a degree 3 of gradualism may be warranted. 4 5 More significant to the concept for a longer ASL than proposed by the Company is the 6 fact that the Company has included significant retirement activity associated with 7 hurricane-related recent events. Normalization of the data to remove hurricane activity 8 would result in raising the OLT from its current position, thus resulting in a longer ASL. 9 Indeed, just removing the 2008 retirement activity for ages 0.5 year through 5.5 years, 10 corresponding to just the 2002-2007 vintage additions, increases the "head" or top 11 portion of the survivor curve by approximately 0.6 of a percentage point. This level of 12 increase is meaningful. 13 14 In addition, Mr. Spanos states in his site visit notes that the Company has historically 15 overloaded its line transformers. This is not a typical practice for an extended period of 16 time and thus, future life expectancy should be longer than that experienced historically. 97 17 Yet another consideration is the fact that Mr. Spanos' industry database indicates that a 18 29-year ASL would be basically at the extreme low end of the industry range. Even 19 retaining the unusually low values in Mr. Spanos' database, the mean, median and mode 20 would all be in the upper 30 to 40 year range, or more in line with the existing ASL. 21 22 Some minimal increase in the ASL above the 31-year ASL (that is as good a fit to the 23 historical data as is the Company's proposal) is warranted in light of industry data, the 24 Company's inappropriate historical actions of overloading transformers, the existing 25 ASL, and the inclusion of hurricane activity in the historical data. Therefore, I am I 26 27 recommending a minimal incremental increase of one additional year as a conservative estimate in favor of the Company. I further recommend that the Commission order the I 28 29 Company to demonstrate the prudence of its continued operation of transformers above maximum ratings, or that it is no longer performing such unusual activity, by the time it 30 files its next depreciation study. 97 Response to Rose City 1-15 Addendum at page 49. 61 1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 2 A. My recommendation for a 32-L0.5 life-curve combination results in a $1,478,940 3 reduction to depreciation expense based on plant in service as of December 31, 2008. 4 5 Account 369 6 7 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 369 - 8 DISTRIBUTION SERVICES? 9 A. The Company proposes a 27-U life-curve combination for both underground and 10 overhead services. 98 11 12 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 13 A. This is one of the accounts where Mr. Spanos relied extensively on his actuarial analysis 14 for his proposal. 99 15 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 16 A. No. A 29-year ASL represents basically the shortest ASL in Mr. Spanos' industry 17 database of approximately 60 values. The only few values that are lower correspond to a 18 Canadian utility, a cooperative and a utility that has not had its proposed ASL tested in a 19 fully litigated proceeding. 100 Moreover, the historical data relied upon by Mr. Spanos 20 incorporates the impact of recent severe hurricane activity, which helps produce the 21 proposed artificially short ASL. 22 23 Q. WHAT DO YOU RECOMMEND? A. 24 25 I recommend a very conservative estimate of a 31-year ASL with an R3 Iowa Survivor Curve. Initial review of Mr. Spanos' proposal raises concern from not only the short ASL I 26 standpoint, but also from the standpoint of the unusual "L4" dispersion pattern. Mr. 27 Spanos' database of other utilities indicates a 40-45 year ASL is indicative of average 98 Exhibit JJS-1 page 53. 99 Id., at page 34. 100 Response to Rose City 1-17. 62 J 1 industry expectations. 101 In other words, the industry indicates a longer ASL than the 2 existing 36-year level, definitely not a reduction to the 27-year level as proposed by the 3 Company. Next, review of Mr. Spanos' industry database further raises concern 4 regarding the proposed "L4" Iowa Survivor Curve. In this existence, Mr. Spanos' 5 judgment relating to what he has observed from the industry and the type of plant in this 6 account should have resulted in further investigation. Indeed, not a single other industry 7 value relies on "L4" dispersion, or for that matter any "L" pattem. 102 8 9 Another consideration that is not addressed by Mr. Spanos is the movement towards more 10 underground rather than overhead services. As reaffirmed by Mr. Spanos' industry 11 database, underground services are generally expected to have a longer ASL than 12 overhead services. l03 The percent investment in underground services has grown faster 13 than for overhead services in the last I 5 years. 104 This fact should have also indicated a 14 longer ASL. Finally, the fact that the Company's data includes hurricane related 15 retirements further demonstrates that a longer ASL than indicated by the OLT is 16 appropriate. 17 18 In order to remain conservative, I am recommending splitting the difference between the 19 existing 36-year ASL and the 27-year ASL proposed by the Company, which yields a 31- 20 year ASL. Such a value still leaves the Company at the very low end of the industry 21 range, well below industry averages, and the existing ASL. I also recommended a "R3" 22 Iowa Survivor Curve, which corresponds to the most frequently used curve in Mr. 23 Spanos' database. In conjunction with my ASL recommendation, I further request that I 24 25 the Commission order the Company to provide a detailed analysis as to why its historical database gives indications of artificially short ASLs and what portion of such lower ASLs I 26 is due to the inclusion of recent hurricane related activity. 101 Id. r 102 Id. 103 Id. 104 I Exhibit JJS-1 pages 289-291. 63 1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 2 A. My recommendation for a 31-R3 life-curve combination results in a $1,159,669 reduction 3 to depreciation expense based on plant as of December 31, 2008. 4 5 Account 390 6 7 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 390 - GENERAL 8 PLANT STRUCTURES AND IMPROVEMENTS? 9 A. The Company proposes a 44-R2.5 life-curve combination. 105 10 11 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 12 A. The Company relies on the results of its statistical actuarial analysis for this account. 106 13 14 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 15 A. No. This is an account that requires special investigation. This account varies throughout 16 the industry because some utilities only rent facilities and have leasehold improvements 17 reflected in this account, while other utilities own the actual structure including the 18 interior components as well as roofs and other systems. The life expectancy for leasehold 19 improvements is much shorter than the life expectancy of an entire office building or 20 warehouse that is owned rather than leased. ETI owns most of its buildings. 107 21 22 Q. WHAT DO YOU RECOMMEND? 23 A. I recommend a 53-R2 life-curve combination as a conservative value. First, it must be 24 noted that a dramatic decline in the OLT as set forth on Exhibit JJS-1 page 176 is a result 25 of an internal decision by the Company to retire, for accounting purposes only, a portion 26 of its corporate headquarters. The investment in that building was subsequently 27 transferred to non-utility plant. In other words, the facility was not actually retired, but 28 reflects an accounting transaction between the regulated and non-regulated portions of 105 Exhibit JJS-1page53. 106 Id., at page 34. 107 Response to Rose City 1-41. 64 l the Company's business. 108 This type of transaction is atypical and should not negatively 2 affect current customers through the depreciation process. Relying on the remainder of 3 the OLT, but eliminating this unusual transaction, would require a substantial increase in 4 ASL. 5 6 In addition, the majority of the investment in this account is associated with office 7 buildings and other structures that the Company owns rather than leases. 109 Office 8 structures, warehouses and similar facilities can normally have life expectancies 9 approaching 75 to 100 years or more. Taking into account that the investments still 10 require a replacement of air conditioning systems, roofs and others components would 11 reduce the dollar-weighted ASL. Mr. Spanos' industry database indicates numerous 12 ASLs for investment in this account that still exceed 50 and even 60 years. In addition, 13 Mr. Spanos' site visit notes state that buildings are generally "concrete slab with steel 14 structures on top."uo Steel buildings on concrete slabs can easily be expected to achieve 15 50 or even 60 years on a dollar-weighted basis. Therefore, my recommended 53-year 16 ASL is conservative in favor of the Company. 17 18 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 19 A. My recommended 53-R2 life-curve combination results in a $299,763 reduction to 20 depreciation expense based on plant as of December 31, 2008. 21 22 Account 391.2 23 24 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 391.2 - GENERAL 25 INFORMATION SYSTEMS? 26 A. The Company proposes a 5-SQ life-curve combination, or a 5-year amortization 27 period. 111 I 108 109 110 Response to Rose City 13-18. Response to Rose City 1-41. Response to Rose City 1-15 Addendum at page 149. 111 Exhibit JJS-1 page 53. 65 I Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 2 A. Mr. Spanos establishes the amortization period based on the anticipated life of the asset 3 over which benefits will be realized. u 2 The amortization period is based on ''judgment 4 which incorporates a consideration of the period during which the assets will render most 5 of their service, the amortization period and service lives used by other utilities and the 6 service life estimates previously used for the asset [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/cases/4067257. Public record. Not legal advice.