Case Information

*0 FILED IN 3rd COURT OF APPEALS AUSTIN, TEXAS 6/2/2015 3:48:59 PM JEFFREY D. KYLE Clerk

*1 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 THIRD COURT OF APPEALS AT AUSTIN, TEXAS Entergy Texas, Inc., et al., 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

*2 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

*3 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 [14 th 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 *4 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 *5 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 PURA 1 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 *6 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 *7 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 *8 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 [14 th 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 *9 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 *10 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 *11 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 *12 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 *13 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 *14 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 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 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.

*17 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 *18 Frontier contract was stepped up. 28 And another intervenor, Cities, adopted ETI’s calculation of rate-year MSS-1 costs. 29

Finally, the MSS-4 30 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 *19 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 *20 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 *21 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 *22 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 *23 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

*24 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 2 nd 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 *25 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

*26 A. Certified copy of Direct Testimony of J. Pous in PUCT Docket No. 37744 22

APPENDIX A

*27 *28 SOAH DOCKET NO. 473-10-1962 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 A TRUE 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 'K.'f Cities Exhibit , ·-· *29 ,I ' *30 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 ........................................................................................................................... 3 8 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 *31 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:

*32 2008 Study 2008 Gannett Fleming Depreciation Study AICPA American Institute of Certified Public Accountants Average Life Group ALG APFD Accumulated Provision for Depreciation ASL Average Service Life CIS Consumer Information Systems Company Entergy Texas, Inc. Public Utility Commission of Texas Commission 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 "not in my backyard" syndrome NIMB NPC Nevada Power Company Nevada Public Service Commission NPSC 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 *33 Reserve Accumulated Provision for Depreciation SGSF Spindletop Gas Storage Facility Sabine Gas Transportation Company SGT SRP Strategic Resource Plan SWEPCO Southwest Electric Power Company FERC Uniform System of Accounts USOA

2 *34 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 PLEASE STATE YOUR NAME AND BUSINESS? Q. A. My name is Jacob Pous and my business address is 1912 W. Anderson Lane, Suite 202,

Austin, Texas 78757.

Q.

WHAT IS YOUR OCCUPATION? A. I am a principal in the firm of Diversified Utility Consultants, Inc. ("DUCI"). A copy of

my qualifications appears as Appendix A.

Q.

HA VE YOU PREVIOUSLY TESTIFIED IN PUBLIC UTILITY PROCEEDINGS? A. Yes. Appendix A also includes a list of proceedings in which I have previously presented

testimony. In addition, I have been involved in numerous utility rate proceedings that resulted in settlements before testimony was filed. In total, I have participated in well over 400 utility rate proceedings in the United States and Canada.

Q.

WHAT IS YOUR PROFESSIONAL BACKGROUND? A. I am a registered professional engineer. I am registered to practice as a Professional

Engineer in the State of Texas, as well as numerous other states.

Q.

ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? A. I am testifying on behalf of the cities of Anahuac, Beaumont, Bridge City, Cleveland,

Conroe, Houston, Huntsville, Montgomery, Navasota, Oak Ridge North, Pine Forest, Pinehurst, Port Arthur, Port Neches, Groves, Nederland, Orange, Rose City, Shenandoah,

I 1 I *35 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? The purpose of my testimony is to address certain adjustments that are required to ETI's 5 A. 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. The following is a brief summary of each of the major areas I address herein. 12 A.

• Production Plant Life Spans. The Company proposes to retire almost all of its gas-fired generation on June 30, 2025, for purposes of calculating depreciation rates in this case as set forth in the 2008 Gannett Fleming depreciation study ("2008 Study"). The proposed retirement year is earlier than and inconsistent with the Company's internal planning for system resources. The Company's proposed depreciation life spans assumes a retirement date that is also artificially short in comparison to the life expectancy by the industry as well as the Company's own resource planning division. I recommend establishing minimum life spans for the Company's gas-fired generating facilities at the later of the year 2029 or when such units reach 65 years of age. The standalone impact of this recommendation is a reduction in depreciation expense of $11. 7 million based on plant in service as of December 31, 2008.

• Interim Retirements. In spite of this Commission's previous rulings and precedent regarding exclusion of interim retirements in the calculation of production plant depreciation rates, the Company still proposes interim retirements in its calculation. The Company's witness, Mr. Spanos attempts to distinguish the Commission precedent by relying on an incorrect premise that the Company's interim retirement analysis is based on a historical perspective, and the Commission's precedent is applicable to a future perspective. This is a distinction without a difference, because the Company applies the result of its historical calculations to projected future results. Therefore, the Company's witness's attempt to distinguish the Company's request from previous Commission decisions is incorrect. The impact of upholding the Commission's long standing precedent against interim retirements results in an approximate $4.6 million reduction in depreciation expense based on plant as of December 31, 2008.

2 *36 • Production Plant Net Salvage. The Company proposes negative net salvage values ranging from a negative 15% to a negative 32% for its gas and coal-fired generations. The Company's coal-fired proposal isbased on an undocumented, unsupported and inappropriate regression analysis associated with a database for which the Company's depreciation witness has no first-hand knowledge. The Company does not have a regression or any mathematical model to estimate net salvage for gas-fired generation, but rather assumes it is approximately 80% of the coal-fired value. Therefore, assuming the 80% factor to be correct, any inaccuracies in the coal regression analysis would carry over to the Company's projected net salvage for gas-fired generation. As a second step to the Company's unsupported net salvage analysis, Mr. Spanos escalates the estimated demolition costs as of the end of 2008 into the future for as many as 35 years and recommends s that current customers pay with current dollars for future inflated costs. These aspects of the Company's analysis are neither credible nor reasonable. Therefore, in consideration of significant increases in scrap metal prices that have occurred in the last 5 years and the potential sale of used equipment, a zero (0) level of net salvage for production plant is recommended. On a standalone basis this recommendation results in a reduction of approximately $11. 7 million in depreciation expense based on plant as of December 31, 2008.

• Mass Propertv Life Analysis. There are numerous problems with the Company's proposed life-curve combination for the various mass property accounts (transmission, distribution and general plant). First and foremost, the Company's life analysis includes the impact of hurricane activity as typical, ongoing events. This has resulted in certain accounts having life expectations shorter than basically all other utilities in the industry. In addition, the Company's consultant recognizes that there is a "significant portion" of the survivor curve to which the curve-fitting process should be geared; however he has failed to properly implement such criteria. Finally, the Company has failed to provide reasonable or adequate support for its various positions. Modifications to 16 of the Company's proposals results in a standalone impact of a $11.1 million reduction to annual depreciation expense based on plant as of December 31, 2008.

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• 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 l consultant in the current El Paso Electric Company case before this Commission. 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 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

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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 *37 I retaining the existing levels of net salvage by account is recommended. On a standalone basis this recommendation results in a $10.6 million reduction in annual depreciation expense based on plant in service as of December 31, 2008.

• Calculation Procedure. The Company proposes to use the Equal Life Group ("ELG") calculation procedure. The ELG procedure is not a conservative capital recovery method and in fact represents an accelerated procedure when compared to the industry standard Average Life Group ("ALO") calculation procedure. The ELG procedure is inaccurate in all instances, except in the improbable scenario that future annual retirements for up to 100 years into the future can be precisely estimated. In reality, ETI cannot predict future annual retirement levels with any degree of accuracy, even for as little as a 5-year period. Relying on the ALO procedure, a straight line, non-accelerated procedure, results in a standalone reduction to annual depreciation expense of $19 .3 million based on plant as of December 31, 2009.

• Combined Impact of Depreciation Adjustments. The combined impact of the various depreciation adjustments is not simply the summation of the individual standalone impacts. If life, net salvage, or calculation procedure proposals are modified within the same account, they are interactive with each other. As set forth on Schedule (JP-1 ), the combined impact of the various adjustments results in a $57 million reduction in depreciation expense based on plant in service as of December 31, 2008.

• Fully Accrued Depreciation. The Company admits that it unilaterally changed the Commission approved depreciation rates when it ceased booking depreciation expense for three accounts. The Company does not have the authority to unilaterally change a depreciation rate previously approved by the Commission. Reversal of the Company's inappropriate actions results in a $6.2 million decrease in rate base and a $1.5 million credit amortization expense associated with a four year amortization period.

• Spindletop Gas Storage Facilitv l"SGSF"). Since the Company's last fully litigated rate proceeding, the Company has exercised an option to purchase the SGSF facilities for $1. Due to the unique situation of ownership, operation and cost recovery, customers have significantly overpaid depreciation expense and are now entitled to appropriate net salvage treatment and correction of the intergenerational inequity that has transpired. Amortizing the excess depreciation reserve over a 4-year period and recognition of Company-established net salvage expectations results in a $5.5 million reduction to revenue requirements associated with this unique investment. However, given Cities' witness Mr. Nalepa's recommendation relating to the SGSF, only $1.2 million of my recommendation associated with the recognition of net salvage is required, when Mr. Nalepa's position is adopted.

4 *38 • Storm Insurance Reserve. The Company has overstated revenue requirements in 1 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 accruals results in a $7. 7 million reduction to the Company's storm reserve annual 8 accrual and a $45.9 million reduction to rate base. In addition, I recommend an 9 increase in the current $50,000 storm insurance threshold limit to $500,000. IO

• Cash Working Capital ("CWC"). The Company overstates and incorrectly calculates the Company's CWC requirements. In particular, the Company relies on an inconsistent implementation of service period between revenues and expenses. There are numerous other flaws associated with the Company's approach to CWC that require correction. Based on my various recommendations, the standalone impact of the corrected lead-lag analysis for the measurement of ewe requirements would result in an incremental $43.7 million reduction to rate base and an approximate corresponding $5. 7 million reduction to revenue requirements.

• River Bend Decommissioning. The Company seeks approval from this Commission for its proposed level of decommissioning expense associated with the River Bend plant that is now owned by ETI's Louisiana affiliate Entergy Gulf States Louisiana ("EGSL"). Cities' witness Mr. Brazell testifies that the Commission does not have the authority to set a decommissioning revenue requirement for River Bend given EGSL' s ownership of the plant. The Company's proposal is based on a 40-year life span for River Bend, rather than the more appropriate and realistic 60-year life expectancy. Therefore, if the Commission were to determine the proper decommissioning revenue requirement for Texas retail customers, I recommend that a 60-year life span be employed. In addition, the beginning balances in the decommissioning funds are understated in the Company's presentation and would need to be corrected. The standalone impact of these adjustments eliminates the need for Texas retail customers to contribute any additional amounts to the decommissioning trust funds. Therefore, 35

l 36 my recommendation results in a $2.8 million reduction to proposed annual 37 decommissioning revenue requirements. 38 • River Bend Depreciation. Cities' witness Mr. Brazell presents the position that 39 the Commission does not have the authority to set depreciation rates for River 40 41 Bend. However, the Company has requested that the Commission do just that. Unfortunately, the Company's presentation reflects a 40-year service life for 42 River Bend. It should be noted that the Company relies on a 60-year life for 43 44 River Bend in the Louisiana jurisdiction and agreed to a 60-year life in Docket No. 34800, a settled proceeding. While the Company has not yet received 45 permission from the Nuclear Regulatory Commission (''NRC") for such license 46

5 *39 extension, it must be noted that not a single license application for the 20-year life extension has been denied by the NRC. Therefore, if the Commission does elect to establish a depreciation rate for River Bend, it should do so based on the 20- year life extension and with no interim retirements reflected therein.

Q. IS THERE A CONCERN THAT NEEDS TO BE ADDRESSED AT THE

BEGINNING OF YOUR TESTIMONY?

A. Yes, in the area of depreciation and capital recovery a utility can present aggressive, middle of the road, or conservative parameters given the subjectivity required in performing any future depreciation or capital recovery estimate. After review of the Company's depreciation presentation, it is clear that the Company's position in this case is one of the most aggressive presentations realistically possible. The Company's approach results in an extremely excessive level of depreciation expense, rapid return of capital investment to shareholders, which in my estimation, is unreasonable and an unnecessary burden for current customers.

Q. DO THE PROPOSED DEPRECIATION PARAMETERS CONTINUE THE CORPORATE PLAN THAT PUSHES AGGRESSIVE DEPRECIATION 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

following: "Push accounting/depreciation judgments aggressively where possible." ^[1] 23 24 (Emphasis added). 25 26 Q. CAN YOU PROVIDE SPECIFIC EXAMPLES THAT DEMONSTRATE ETl'S CONTINUATION OF THE PREVIOUSLY STATED AGGRESSIVE 27 28 DEPRECIATION PRACTICES? 29 A. Yes. First and foremost is the Company's decision to utilize the ELG calculation procedure. Reliance on the ELG procedure in light of identifiable "anomalies" that result 30 31 from the analyses of the underlying data is flawed and can no longer be relied upon to

*40 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 EGSL. Indeed, the combination of the underlying data problems with the fact that the 4 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 I 0 unsubstantiated regression analysis that produces excessively negative values, but then

proposed a unique escalation calculation. The Company, through Mr. Spanos' testimony, proposes to charge current customers, who would have to pay with current dollars, for costs that have been escalated, without discounting costs back to the present, for as many as 35 years into the future. Such approach is illogical and unrealistic. While there are other actions taken by Mr. Spanos that further push his and the Company's aggressive depreciation goals, the above examples more than establish the nature of the Company's presentation.

SECTION II:

DEPRECIATION General 1. 21

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22 Q. WHAT IS DEPRECIATION? There are two commonly cited definitions of depreciation. The first comes from the 23 A.

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24 Federal Energy Regulatory Commission's ("FERC") Uniform System of Accounts ("USOA"): 2 25 l 26 'Depreciation', as applied to depreciable plant, means the loss in service value not restored by current maintenance, incurred in connection with 27

I the consumption or prospective retirement of electric plant in the course 28 *41 7 of service from causes which are known to be in current operation and against which the utility is not protected by insurance. Among the causes to be given consideration are wear and tear, decay, action of the elements, inadequacy, obsolescence, changes in the art, changes in demand and requirements of public authorities.

The second definition, from the American Institute of Certified Public Accountants ("AICPA"), is similar:

Depreciation accounting is a system of accounting which aims to distribute the cost or other basic value of tangible capital assets, less salvage (if any) over the estimated useful life of the unit (which may be a group of assets) in a systematic and rational manner. It is a process of a/location, not of valuation. Depreciation for the year is a portion of the total charge under such a system that is allocated to the year. Although the allocation may properly take into account occurrences during the year, it is not intended to be a measurement of the effect of all such occurrences.

Q. WHAT ARE THE TWO GENERAL FORMULAS USED IN DETE RMINING DEPRECIATION RATES?

19 A. The whole life and the remaining life technique are the most commonly used formulas. The whole life technique is as follows: 3 20 [ Original Cost - Net Salvage J Depreciation Rate (%) = Average Service Life Original Cost The remaining life technique for calculating depreciation rates is as follows: 21 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.

*42 8 The two formulas should equal each other when the difference between the theoretical reserve and the actual Accumulated Provision for Depreciation ("APFD" or "reserve") are recovered over the remaining life of the investment under the whole life formula.

Q. ARE THERE ADDITIONAL CONSIDERATIONS IN DEPRECIATION BEYOND THE DEFINITIONS? A. Yes. The definitions provide only a general outline of the overall utility depreciation concept. In order to arrive at a depreciation-related revenue requirement in a rate proceeding, a depreciation system must be established.

Q. WHAT IS A DEPRECIATION SYSTEM?

A. A depreciation system constitutes the method, procedure, and technique employed in the

development of depreciation rates.

Q.

BRIEFLY DESCRIBE WHAT IS MEANT BY "METHOD". A. Method identifies whether a straight-line, liberalized, compound interest, or other type of

calculation is being performed. The straight-line method is normally employed for utility depreciation proceedings.

Q.

BRIEFLY DESCRIBE WHAT IS MEANT BY "PROCEDURE". A. Procedure identifies a calculation approach or grouping. For example, procedures can

reflect the grouping of only a single item, items by vintage (year of addition), items by broad group or total grouping, and equal life groupings. The vast majority of utilities and

I regulatory authorities use the ALG procedure. I Q.

PLEASE BRIEFLY DESCRIBE WHAT IS MEANT BY "TECHNIQUES".

A. There are two main categories of techniques with various sub-groupings: the whole life I 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 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

*43 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 IMP ACT THE CALCULATION OF 18 DEPRECIATION? 19 A. The intent of the depreciation process is to allow the Company to recover 100% of

investment less net salvage. Therefore, if net salvage is a positive 10%, then the utility should only recover 90% of its investment through annual depreciation charges, under the theory that it will recover the remaining 10% through net salvage at the time the asset retires (e.g., 90% + 10% = 100%). Alternatively, if net salvage is a negative 10%, then the utility should be allowed to recover 110% of its investment through annual depreciation charges so that the negative 10% net salvage that is expected to occur at the end of the property's life will still leave the utility whole (e.g., 110% - 10% = 100% ).

Q.

WHAT ARE THE KEY ELEMENTS OF THE DEPRECIATION FORMULA AT

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

*44 10 data, the judgment and experience of the analys~ and other relevant information. In addition, the remaining life calculation is at issue given that Mr. Spanos of Gannett Fleming performs a different remaining life calculation than every other utility that does not retain Gannett Fleming that I have dealt with over the past 3 7 years, including this Company. This remaining life calculation produces theoretically impossible results. Finally, the calculation procedure is a major issue in this case, as ETI does not rely on the industry standard ALG procedure. 2. Production Life

A. General Q. WHAT IS THE ISSUE IN TlllS PORTION OF YOUR TESTIMONY? A. This portion of my testimony addresses the appropriate life spans for the Company's

various generating units. In particular, I will address what appears to be a practice of understating the life span for generating units. I recommend longer life spans for the Company's gas-fired generating units.

Q. WHAT IS A LIFE SPAN FOR A GENERATING UNIT? A. A life span for a generating unit sets the period during which it is expected to be in

service prior to being retired. For example, if a generating unit was placed into service on January 1, 1980 and had a 60-year estimated life span it would have a projected 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. I 26 In determining the depreciation rate, and thus depreciation expense for a generating unit, A. 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 regulatory "matching principle." As previously noted, the depreciation formula includes 29 *45 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

ARE THE RETIREMENT DATES FOR GENERATING UNITS KNOWN WITH

7 Q. CERTAINTY? 8 9 A. Not for most units. Even for nuclear units that must operate within the period of a license granted by the NRC, we now know that the initial estimate of a 40-year life span has been

10 or will be expanded to 60-years. Indeed, in ETI's last case, Docket No. 34800, the life 11

span for River Bend was extended for ratemaking purposes to 60 years. 4 12 13

WHEN SETTING THE LIFE SP AN FOR A GENERATING UNIT, IS IT

14 Q.

APPROPRIATE TO LIMIT THE TIME FRAME TO THE INITIAL ESTIMATED PERIOD CORRESPONDING TO WHEN MAJOR CAPITAL ADDITIONS MAY BE REQUIRED IN ORDER TO KEEP THE UNIT IN SERVICE?

A. No, even though ETI and its depreciation consultant, Mr. Spanos, attempt to rely on such a concept to artificially limit the current estimate of life span for units. Indeed, it is questionable whether even the Company really believes such less than credible argument given the sizeable capital additions it had to make in the early stages of service life for its gas fired units. 5 In recognition of these sizeable capital additions that were necessary to keep the units operating, ETI did not attempt to limit the life spans in its earlier depreciation studies to the date of the expected capital additions.

*46 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? It is inappropriate to implement such depreciation judgment because it assumes that 4 A.

utilities will act differently in the future than they have acted in the past without the benefit of specific factors that would warrant such a change. Generating units are very capital-intensive items. Economic theory recognizes that it is normally expected that capital expenditures and normal maintenance expense will not only be made, but encouraged as necessary, to keep a large capital intensive facility in operation for as long as economically practical. This has been the Company's practice as it applies to actual operation of its units. An analogy would be associated with the purchase of a home. A new home can easily be expected to last well over 50 years. However, a major capital expenditure for a new roof may be required after 15 to 20 years. No reasonable person would set the life expectancy of the house at 20 years because the decision has not been made regarding an expected major expenditure 20 years in the future. The same can be said about limiting the expected initial life expectancy of a house to even 30 or 40 years when the second replacement of a roof can be expected. The issue becomes at what point would one expect external forces such as a change in character of the neighborhood or other events to change, for it to warrant the abandonment of the house. As long as the best use of the house is as a dwelling and it is economically cost effective to make repairs and replacements, the initial life should not be set artificially short due to potential

I uncertainties surrounding future major capital additions. I 26 Q. DOES THE COMPANY'S PRODUCTION PLANT DEPRECIATION EXPENSE

27 REPRESENT A SIGNIFICANT REVENUE REQUIREMENT? I 28 A. Yes. The Company's 2008 Study identifies over $783 million of investment and proposes 29 $28.4 million in depreciation expense for annual Steam Production plant (Accounts 310- l 30 316). 6 This level of depreciation expense is unnecessary and only arises as a result of the ^[6] *47 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 COMP ANY SPECIFICALLY PROVIDE IN

SUPPORT OF THE PROPOSED LIFE SPANS FOR ITS VARIOUS 6 7 GENERATING UNITS? 8 A. The Company provided the testimony of Mr. Spanos. The entire basis for this significant

parameter is set forth at pages 19 and 20 of Mr. Spanos' direct testimony where he states: The bases for the probable retirement years are life spans for each facility that are based on judgment and incorporate consideration of the age, use. size. nature of construction. management outlook, and typical life spans experienced and used by other electric utilities for similar facilities. Many of the life spans result in probable retirement years that are many years in the future, but included as part of ETI' s resource plan. As a result, the retirements of these facilities are not yet subject to specific management plans. At the appropriate time, detailed studies of the economics of rehabilitation and continued use or retirement of the facility will be performed and the results incorporated in the estimation of the facility's life span. (Emphasis added).

Q.

DID THE COMPANY ADD ANY ADDITIONAL INFORMATION REGARDING THE BASIS FOR THE LIFE SP ANS OF ITS UNITS IN THE 2008 DEPRECIATION STUDY?

A. While the 2008 Study added the following statements, such verbiage fails to provide any additional meaningful basis for the Company's proposed life spans: The life span estimates for power generating stations were the result of considering experienced life spans of similar generating units, the age of surviving units, general operating characteristics of the units, major refurbishing, and discussion with management personnel concerning the probable long-term outlook for the units. Final decisions as to date of retirement will be determined by management on a unit by unit basis. ^[7] (Emphasis added).

*52 18 Q. WHAT SOURCE SUPPORTS YOUR POSITION THAT ESTIMATED INTERIM ADDITIONS SHOULD NOT BE REFLECTED IN THE DEPRECIATION CALCULATION?

A. The National Association of Regulatory Utility Commissioners (''NARUC") 1968 publication entitled Public Utility Depreciation Practices describes, on pages 133 and 134, how interim additions are treated. It states the following:

Appropriate computations must be made for such interim retirements, but interim additions are not considered in the depreciation computation until they are actually made. It is possible to estimate the probable future retirements and additions to a particular piece of property and thus arrive at a single depreciation rate applicable over the entire life of the property. This is an unsatisfactory practice inasmuch as considerable speculations would be required to make such an estimate on future additions. In any event. this is not necessary inasmuch as the depreciation accrual can be adjusted in future years as additions are made. (Emphasis added).

The 1996 NARUC depreciation publication reaffirms this concept. ^[12] Q. HAS THE FERC RENDERED A DECISION ON THE CONCEPT OF

INTERIM ADDITIONS?

A. Yes. The FERC reviewed and ruled on this issue in its Opinion No. 165, a Commonwealth Edison Company case. ^[13] In that case, Commonwealth Edison had proposed taking into account budgeted future interim additions and stated that without the inclusion of the budgeted interim additions, there would be a violation of the matching

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principle (i.e. revenues collected corresponding to the expenses incurred). In Opinion No. 165, the FERC clearly rejected recognition of interim additions:

I ... we reject its [Edison 'sj claim that this will leave some costs unrecovered after the plant is retired. Such a result might occur if Commonwealth would fail to adjust its depreciation rates from time to

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time, taking into account up-to-date information on changes in plant

balances, estimated remaining life, salvage and removal cost experience, and accumulated provision for depreciation to date. However,

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*55 ^[16] Exhibit JJS-1page36. ^[17] Response to Rose City 1-36. ^[18] Response to Rose City 1-3, 2008 Study for EAi at page 11-27. ^[19] EIA FORM 860, file Gen YOS.

I 21 I 1 Q.

WHAT DO YOU RECOMMEND?

2 A. Given the industry, even here in Texas, is moving to a minimum of 60 years for coal fired generation and 60 plus years for gas-fired generation, I recommend a life span for all gas-fired units corresponding to the year 2029 for those units that will exceed 65 year life spans by that time, and a life span of 65 years for the remaining units. The year 2029 corresponds to the earliest year subsequent to the Company's current planning horizon in its SRP. 3. Production Interim Retirements

Q.

WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY? A. This portion of my testimony addresses the Company's request for interim retirements

and the corresponding impact on the life span for production plant. Q. WHAT ARE INTERIM RETIREMENTS?

A.

Interim retirements have been characterized as a fine-tuning adjustment to the life-span analysis. The life-span method is used in estimating the retirement date for any large unit of property such as an entire generating facility to recognize that through the course of its 60-year life span, several components of that generating facility will be changed. The theory behind interim retirement rates is that even though a large unit of property, such as a generating facility might retire in 60 years, in the interim period many components have to be replaced in order to maintain the overall generating facility in operating condition. An analogy to this would be a car, which might be anticipated to have a service life of 10 years. During the 10-year life of the car, the owner might have to replace the battery, tires, alternator and other components in order to maintain the automobile in a safe and operable condition. Therefore, even though the automobile may have a 10-year life span, a 9.8-year average service life ("ASL") for the automobile and its components would result due to the averaging of the automobile's life span with the average of the individual components. In other words, the interim retirement rate would be a fine-

*56 29 tuning factor used to reduce the service life from 10 years to a 9.8 year ASL. 22 Q. HAS THE COMPANY INCORPORATED THE IMPACT OF INTERIM

RETIREMENTS IN ITS DEPRECIATION ANALYSIS?

Yes. ^[20]

A.

Q. HAS THE COMMISSION PREVIOUSLY REJECTED THE INCLUSION OF

INTERIM RETIREMENTS IN THE CALCULATION OF PRODUCTION PLANT DEPRECIATION RATES?

A. Yes. The Commission has specifically and consistently excluded interim retirements from prior production-plant depreciation-rate calculations in fully litigated rate cases. In Docket Nos. 14965 and 16705, the most recent fully litigated major electric base rate cases where interim retirements were an issue, the Commission once again reaffirmed its position and rejected the inclusion of interim retirements from the depreciation rate calculation for production plant. In Docket No. 14965 the Commission stated " ... forecasted interim additions and retirements and net salvage increases to plant in service are not known and measurable changes to test-year invested capital." 21

(Emphasis added). In Docket No. 16705 the Commission denied the impact or recognition of all interim retirements and additions beyond the end of the test year. ^[22] The Commission has also denied the inclusion of interim retirements in cases where I also recommended their inclusion.

Q. WAS MR. SPANOS AWARE OF COMMISSION PRECEDENT WHEN HE

PROPOSED THE INCLUSION OF INTERIM RETIREMENTS?

A. Yes. However, he believed that the precedent dealt with future interim retirements, not historical interim retirements. 23 While his analysis of interim retirements was based on I historical data, the results were applied to future remaining lives because Mr. Spanos thinks "that is a good indicator of what is going to happen into the future for interim

~ retirement purposes." 24 Mr. Spanos' approach is no different than the practices of other utilities where the Commission rejected the use of interim retirements. In fact, Mr.

~ ^[20] *57 Direct Testimony of Mr. Spanos at page 18.

I

^[21] Docket No. 14965 FOF 94. ^[22] Final Order Docket No. 16705 at FOF 186. ^[23] Deposition of Mr. Spanos on March 25, 2010 at TR 93-94.

I ^[24] Deposition of Mr. Spanos on April 20, 2010 at TR 95-96. 23 I l Spanos could not identify any docket where this Commission had allowed interim retirements as he would characterize them. 25 2 3 4 Q. IF THE COMl\flSSION WERE INCLINED TO REVERSE ITS PRECEDENT ON 5 TIDS ISSUE IN Tms CASE, DO YOU BELIEVE THE ANALYSIS PRESENTED 6 BY THE COMPANY IS APPROPRIATE? 7 A. No. 8 9 Q. WHAT DOES THE COMPANY PROPOSE FOR INTERIM RETIREMENTS? The Company proposes to implement a calculation procedure for interim retirements 10 A.

based on a truncated interim retirement survivor curve. 26 11 12 13 Q. PLEASE EXPLAIN THE PROBLEMS WITH THE COMPANY'S PROPOSED 14 METHOD. The Company's approach relies on an actuarial analysis of the historical data for the 15 A.

investment in Accounts 311 through 316. 27 Actuarial analyses are normally performed on more homogenous-type investments. The types of investments booked in the major steam production plant accounts are non-homogeneous and do not reasonably lend themselves to actuarial analyses. In other words, the retirement forces experienced by boiler tubes booked in Account 312 may be noticeably different than those affecting the lighting system, also booked in Account 312. Moreover, the retirement of individual units of property in Account 312 can vary significantly. Therefore, Mr. Spanos' reliance on an inappropriate method, which in turn relies on non-homogenous data to "guess" at a 55-R2 life-curve combination for the largest production plant account, is inappropriate. I use the term "guess" given the fact that Mr. Spanos analysis yielded a survivor curve that only declined by 12 percentage points out of 100 percentage points for a full curve. He simply "guesses" or forces a result for the remaining 88%. Moreover, his "guess" at the 12% decline in the observed life table ("OLT") was not good or reasonable. 28 If the *59 purposes in this proceeding and the impact of interim retirements be eliminated from the

23 I Company's proposed depreciation calculation. 24 I ^[29] FPSC Docket No. 080677-EI Order at pages 30-32. 25

I

1 Q.

WHAT IS THE IMP ACT OF YOUR RECOMMENDATION?

2 A. The total standalone impact of the elimination of the proposed interim retirements from 3 production plant depreciation rates results in a reduction to the Company's requested depreciation expense by $4,608,437 based on plant as of December 31, 2008. 4 5 4. Production Net Salvage 6 7 Q. WHAT ISSUE DO YOU ADDRESS IN TIDS PORTION OF YOUR 8 TEST™ONY? 9 A. I address the Company's request for production net salvage. Specifically, the Company

requests net salvage for its various generating facilities ranging from a negative 15% to a negative 32% for its various generating facilities. 30 In response to the Company's proposal, I recommend a zero (0) level of net salvage, even though a more appropriate, yet still conservative, level would be a positive 5% to 10%.

Q. WHAT DOLLAR IMPACT DOES THE COMPANY'S PROPOSAL HAVE ON

DEPRECIATION EXPENSE?

A. Based on plant in service as of December 31, 2008, the Company's net salvage request of $190.7 million over the life of the investment produces approximately $11.6 million of annual depreciation revenue requirements. 31 WHAT IS THE COMPANY'S BASIS FOR ITS REQUEST OF NEGATIVE NET

Q.

SALVAGE?

Mr. Spanos states the following: A. final net salvage of dismantling costs of steam production units was based on common industry practices of linear regression analysis by Megawatts (capacity). These analyses were performed as of 2008 and the overall dismantling costs were projected to the date of removal. 32

*61 29 30% of Nelson 6. Therefore, Mr. Spanos' calculation overstates the dismantlement cost

I

*64 34 point reflects 21 megawatts, while the largest data point reflects 3,145 megawatts. I am 35 unaware of any single generating unit that begins to reflect a size even approaching 3,000 36 MW.

30 1 2 Q. DO VALUES IN MR. SPANOS' REGRESSION DATA SET REPRESENT UNREALISTIC RANGES? 3 4 A. Yes. For example, at the low end of the MW size range, Mr. Spanos identifies a 21 MW 5 and a 23 MW unit. The observed values for these two similarly sized coal units are a $38.14 per kW dismantlement cost and a $119.22 per kW dismantlement cost, 6 7 respectively. This cost range represents in excess of a 3 to I variance from the low value to the high value. Ranges of this magnitude for the same type and size units call into

I 8 question the validity of the data. However, Mr. Spanos does not have the underlying data 9 IO and cannot explain such variances. 11 12 Q.

IS THE UNREALISTIC LEVEL OF VARIANCE LIMITED TO ONLY THE

SMALLEST SIZE UNITS? 13 No. For example, Mr. Spanos' database includes a 610 MW and a 630 MW unit with 14 A. corresponding estimated decommissioned costs of $8.96 per kW and $84.33 per kW, 15 respectively. Again, this range represents a differential in excess of 9 times from the low 16 value to the high value. Ranges of this magnitude for similar size and type units 17 18 demonstrate that Mr. Spanos' unsubstantiated database does not produce credible values. 19 20 Q. DOES THE FACT THAT MANY OF THE VALUES FALL WITHIN MORE REALISTIC RANGES HELP JUSTIFY RELIANCE ON THE REGRESSION 21 ANALYSIS? 22 23 A. No. Without access to the underlying data, we do not know whether the majority of the values in the more plentiful middle range are not a function of cost estimates from the 24 same cost estimator firm, thus further diminishing the credibility of the database. 25 26

~ 27 Q. YOU STATE THAT THESE VALUES ARE ESTIMATED VALUES, DOES MR. *65 ! 28

SP ANOS AGREE WITH YOU?

No. During Mr. Spanos' deposition, he stated that he believed that the values reflected in 29 A. I 30 his database were for actual demolition activity, rather than estimated demolition cost I 31 I studies. 39 Mr. Spanos' understanding of the data is based on his undocumented 1 discussions with his predecessors at Gannett Fleming. 40 2 3 4 Q.

IS MR. SPANOS CORRECT?

No. This is the first time I have heard Mr. Spanos claim that these were actual demolition 5 A. cost studies. For example, when Mr. Spanos relied on a regression analysis for his proposed production plant net salvage proposal in a Nevada Power Company (''NPC") case before the Nevada Public Service Commission (''NPSC"), he believed the values were from estimated cost studies. 41 In that case, Mr. Spanos also stated that the "data [demolition cost information] were obtained from a survey conducted by the Property Accounting and Valuation Committee of the Edison Electric Institute.''4 2 However, Mr. Spanos' statements regarding these studies included discussion of different contingency factors between studies. If the data represented actual completed demolition of power plants, there would be no need for references to contingency factors. Contingency factors are only applicable to future occurrences. The most troubling aspect of this situation is that Mr. Spanos now claims he has even less of the limited data he had in the NPC case associated with the old demolition cost estimates in this case.

Q. IS THERE YET ANOTHER PROBLEM WITH THE RELIANCE ON A 20-YEAR OLD UNIDENTIFIED DATABASE?

21 A. Yes. Productivity rates and types of potential demolition activities have changed over time. For example, there now exists a mechanical boom that can reach 300 ft high with 22 23 sheers on the end that can sever large beams of steel. This type of equipment has changed the productivity levels reflected in whatever studies Mr. Spanos relied upon in 24 comparison to today's activity. In addition, Mr. Spanos' reliance on demolition cost 25 26 studies fails to recognize that many portions of units may be sold, which diminishes the 27 level of negative net salvage or, in fact, results in positive levels of.net salvage. Another *66 28 consideration that Mr. Spanos fails to take into account is the possibility of reuse of the

*67 I l

*68 36 are silent on that issue and make no provision for inclusion ofinflation .... 37 38 Finally, the Commission also agrees with Staff and ABATE that it is 39 unreasonable to charge current ratepayers for future estimated costs of 40 removal that are escalated for inflation ... Although magnifying the costs, *69 30 I recommend a zero (0)-level of net salvage for steam production plant as a conservative A.

I 31 position. The Commission may find it appropriate to adopt a positive 5% or greater level 32 of net salvage for steam generating facilities in recognition of: (1) the significant increase I 33 in scrap metal prices that have occurred during the last 5-7 years due in part to the 34 significant growth by the economies of China and India; and/or (2) recognition of 35 l potential total sale of generating unit, or partial sale of used equipment as operable 2 equipment, rather than a sale as scrap value. 3 4 Q. DID MR. SPANOS CONSIDER THE POTENTIAL THAT A POSITIVE NET 5 SALVAGE COULD BE OBTAINED EVEN THROUGH A DEMOLITION 6 PROCESS? 7 A. No. Mr. Spanos stated that he "would be very surprised that there is much of a market for 8 someone to come in and buy it [a generating unit] for the scrap value and consider that to 9 be more than the cost they will have to dismantle it when they have eventually walked

away from that site.'.4 6 10 11 12 Q. ARE YOU AWARE OF A RECENT SITUATION WHERE A DEMOLITION CONTRACTOR PAID TO TAKE DOWN A POWER PLANT? 13 Yes. Just last year the King Power Plant in Ft. Pierce, Florida was being demolished. 14 A. 15 Even though the cost estimator developed a study that estimated a substantial cost to 16 demolish, the winning bid to demolish the plant was a negative $974,000. In other words, 17 a contract offered to lli!Y almost $1 million to get the salvageable equipment and scraps 18 material while demolishing the plant. The winning bid also included substantial costs for

the removal of asbestos at the old plant. 47 19 20 COULD TIDS BE A SITUATION WHERE A CONTRACTOR WAS JUST OUT 21 Q.

OF LINE WITH ms ESTIMATE? 22 23 A. No. In fact, there were four bids where contractors were willing to lli!Y between $250,000

and $600,000 for the right to demolish the plant. 48 24 25 Q. IS THERE AN AFTER MARKET FOR EQUIPMENT THAT WAS DESIGNED

I FOR OLDER POWER PLANTS? 26 *70 Yes. For example, the city of Traverse, Michigan, recently retired the 1940s vintage 27 A. 28 Bayside generating station. As part of the demolition, a sugar cane grower from Central *72 25 Q. PLEASE PROVIDE MORE INFORMATION REGARDING HOW A 26 DEPRECIATION ANALYST PERFORMS SUCH A LIFE ANALYSIS THAT 27 RELIES ON AN ACTUARIAL APPROACH. 28 A. Aged data is gathered and analyzed. Aged data means that when an asset retires in 2008

we know that it originally went in service in 1968, and was 40 years old at the time of 29 30 retirement. When all the aged data in a group is statistically analyzed by actuarial

38 1 techniques a resulting Observed Life Table or OL T is developed that depicts the rate of 2 retirement over the life of the group. The OLT starts at 100% surviving and declines 3 from there as each year of age is obtained and retirements occur. Naturally, not all units 4 retire at once; instead, the retirement dates are dispersed through time, creating a 5 "dispersion pattern." In order to permit testing and smoothing of the results some 6 standard or index must be used. The principal tool that a depreciation analyst uses for 7 this aspect of the study is a set of "survivor curves." The industry standard and most 8 extensively used curves are called the Iowa Survivor Curves. The name is derived from 9 the fact that they were developed at Iowa State College in the 1930s.

IO

Often, the historical data base analyzed does not yield a complete OLT, one that fully declines to 0% surviving. This means that the data set will produce an incomplete OLT or a "stub curve." Also, the limited data base may include atypical or abnormal events not reasonably anticipated to occur again during the remaining life at the same levels reflected in the historical data. The Iowa Survivor Curves are based on empirical studies of retirement "behavior" of physical property. They are designed to predict the retirement patterns of the property under study based on detailed past observations. The Iowa Survivor Curves make the calculation of the ASL far more manageable and comparable; instead of making and weighting a myriad of individual calculations that include each data point in the universe, the analyst measures the area below the curve and uses an established equation or standard curve to "solve" for the ASL. And, even ifthe data set is incomplete-which is often the case -by properly choosing a closely fitting curve to the known data, the analyst can better predict the behavior of the entire universe and calculate the ASL with reasonable statistical accuracy, if a meaningful "stub curve" exists. The results of any

*73 27 estimation are more reliable if 70% of an OLT is known and only 30% must be assumed, 28 than if only 10% of the OLT is known and 90% must be assumed. 29 30 Not surprisingly, choosing the survivor curve that provides the best fit to the data is 31 critical to the accuracy of the analysis. When fitting the curves to the OLT the analyst 32 must bear in mind that some data points-those that occur on the points of the graph that

39 reflect the most significant level of plant exposed to retirement events-- are more important to the determination of the ASL and dispersion pattern than others. Further, the analyst cannot use the curves in isolation of other considerations. The analyst must incorporate such things as knowledge of the nature of the property being studied, an understanding of the causes of unusual events, recognition of changes or trends, and judgment when using the curves. Also, the nature of survivor curves limits their usefulness. For instance, they are best suited to studies of homogeneous items that, because of their physical similarity and common exposure to retirement forces, can be expected to share common retirement characteristics. (By analogy: When an insurance actuary performs a mortality/longevity study for life insurance purposes, the actuary does not combine people and horses in the universe of data.) It is for that reason that I criticized ETI's analyst for inappropriately applying the Iowa Survivor Curves to interim retirements for generation plant. The items of generation plant involved in interim retirements frequently are far from homogeneous. HAVE YOU REVIEWED THE COMPANY'S MASS PROPERTY LIFE

Q.

ANALYSES?

18 A. Yes, I have reviewed the Company's mass property life analyses. The main problem 19 with the analyses is that Mr. Spanos proposes ASLs with corresponding Iowa Survivor 20 Curves that are not the best fitting results for the actuarial analyses, even when the final 21 proposal is based on actuarial results. Mr. Spanos' selections for most accounts reflect a 22 bias toward artificially short ASLs. It is unreasonable and inappropriate to ignore the 23 best fitting life analyses without detailed and credible explanations. Mr. Spanos fails to 24 provide support for his questionable practice. 25 Q.

BASED ON YOUR REVIEW OF THE COMP ANY'S LIFE ANALYSES AND

*74 26 OTHER INFORMATION, ARE YOU RECOMMENDING ADJUSTMENTS? 27 A. Yes. I recommend adjustments to 16 accounts or subaccounts. The recommendations, as 28 well as the Company's proposals for each of the accounts where a change is 29 recommended, are set forth in the table below.

40

MASS PROPERTY LIFE SUMMARY

ETI Cities Difference based Proposed Recommended on Plant as of 12/31/2008 ASL Curve ASL Curve Account Descrintion ASL Imnact53 350 Transmission Land Rights 65 R4 95 R4 30 $183,605 353 Transmission Station Equipment 45 R2.5 52 R2.5 7 $1,462,347 354 Transmission Towers 50 S4 63 S4 13 $110,162 355 Transmission Wood & Steel Poles 55 R3 59 R2.5 4 $1,080,733 356 Transmission Overhead Conductors 53 R2.5 55 R2.5 2 $210,829 R4 85 R4 360 Distribution Land Rights 55 30 $120,195 so 362 Distribution Station Equipment 40 Rl.5 46 6 $783,405 365 Distribution Overhead Conductors 36 R0.5 39 S0.5 3 $1,103,876 366 Distribution Underground Conduit 50 R2 60 R3 10 $182,339 so 368 Distribution Line Transformers 29 32 L0.5 4 $1,478,940 369 Distribution Services - Overhead 27 L4 31 R3 4 $1,159,669 3 90 General Structures & Improvements 44 R2.5 53 R2 9 $299,763 5 SQ 391.2 General Information Systems SQ 10 5 $1,423,792 394 General Tools, Shop & Garage 15 SQ 20 SQ 5 $187,514 397 .1 General Communication Equipment 10 SQ 15 SQ 5 $167,904 *75 397.2 General Communication Equipment 15 SQ 20 SQ 5 $1,136,473

Microwave *76 Yes. It would be foolish to accept the results of a standardized life-curve that better fits 25 A. 26 the results of the end or "tail" of the OLT rather than a life-curve combination that is a 27 better fit near the "head" or top and upper portions of the OLT. While it is desirable to 28 have close fitting results all along the OL T, this unfortunately does not occur for many

S4 Id. ss Deposition of Mr. Spanos on April 25, 2010 at TR l 12. s ^[6] Direct Testimony of Mr. Spanos at page 34.

42 l accounts. Therefore, recognition of the dollar level of exposures at different points of the OLT is critical. This is significant, since as each new year of plant activity transpires, the OL T can and usually does change. However, the future changes will not occur equally to all portions of the OLT. In fact, it is unlikely, given the level of exposures near the "head" or top of the OLT, that the few years between depreciation studies would result in any appreciable movement of that portion of the OLT absent unusual events. The same cannot be said of the "tail" portion of the OLT, and potentially even the mid portion of the curve. If larger retirements transpire in older age intervals, or more dollars of exposures filter further down in the OLT without corresponding retirements, the mid portion or tail of the OLT can move significantly, based on only a few years of additional data. That is precisely why matching the "head" and other significant portions of the OL T is more important than matching the ''tail." B. Account Specific Adjustments

Account 350.2

Q.

WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 350.2 -

TRANSMISSION LAND RIGHTS?

The Company proposes a 65-year ASL with a corresponding R4 dispersion pattern. 57

A.

22

I

23 *77 Q. WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL? 24 A. This is one of the accounts where Mr. Spanos based his proposal on judgment, the nature

I

25 of the plant and equipment, the previous estimate for this Company and a general knowledge of service lives of similar equipment in other utilities. 58 26

I

*78 25 same right-of-ways in the future, thus requiring an extension of my recommended ASL at I 26 some point in the future. *79 24 Spanos apparently discounted the Company specific activity, it is clear that the Company has substantial levels of investment that have already exceeded the Company's proposed 25

I 26 short ASL. Indeed, a better curve fit to the meaningful or significant portion of the data indicates that a longer ASL is a better representation of the historical data than is the 27 I 28 Company's proposed 45-year life. In fact, as shown in the graph below, the 52-year ASL I recommend is a superior fit to the Company's data. 29 *80 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

in that database. ^[64] Mr. Spanos' notes also support something longer than a 45-year ASL. 7 8 For example, Mr. Spanos' notes associated with substations specifically state "about 50

*81 I 24 his generalized statement referring to judgment and other information. 25 26 Q. DO YOU AGREE WITH THE COMP ANY'S PROPOSAL? A. No. I recommend a 63-S4 life-curve combination. 27

I I

*82 24 25 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? This is another account where Mr. Spanos claims to have relied on the statistical actuarial 26 A.

results. 70 27

I

*83 *84 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

decision making process. 72 Otherwise, he would have proposed a longer ASL. Thus, from 5 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. *85 23 significant portion of the curve, but the longer ASL continues the good fit through most

I of the remaining portion of the OL T including portions of the curve that are still 24 significant. Another consideration for a somewhat longer ASL is that to the extent any 25

I retirement activity associated with major hurricanes that occurred in recent periods is 26 reflected in the Company's data, it would understate the expected ASL for the remaining 27

l 28 investment. Therefore, a modest increase from what the Company has proposed in the expected ASL is warranted at this time. 29 *86 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. Accounf 360 4 5 6 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 360 - DISTRIBUTION LAND RIGHTS? 7

The Company proposes a 55-R4 life-curve combination. ^[75] 8 A. *87 22 23 Q.

WHAT DOES THE COMP ANY PROPOSE FOR ACCOUNT 362 - I 24 DISTRIBUTION STATION EQUIPMENT? The Company proposes a 40-Rl.5 life-curve combination. 76 25 A. I 26 27 Q.

WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? I This is an account where the Company relied on what appeared to be a good to excellent 28 A. statistical indication from its statistical analysis of historical data. 77 29 *88 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

the first 70 years of age. ^[81] The impact of this single age bracket produced an atypical and 23 24 noticeable decline in the OLT as set forth in the graph in the Company's depreciation

study. ^[82] Events of this magnitude warrant further investigation, yet Mr. Spanos' 25 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

*89 I I I

*90 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 expense based on plant as of December 31, 2008. 3 I Account 365 4 5 I Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 365 - 6 DISTRIBUTION OVERHEAD CONDUCTORS? 7

The Company proposes a 36-R0.5 life-curve combination. 87 A. 8 1 *91 I I I '

*92 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,

conductors may not be damaged and thus still in use. 90 All else equal, this would imply 3 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 1 O hurricanes that occurred in the 2005 through 2008 era for use in the next depreciation *93 Company is proposing a 10-year reduction based on undefined judgment. A review of the

20 data indicates unusually high levels of retirement activity at low age intervals, without 21

any explanation. 93 Substantial amounts of these early age retirements are associated with 22 underground plastic conduit and pads for transformers. These are not the type of 23

I 24 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 25 26 artificially short. Indeed, Mr. Spanos' industry data, which is skewed with several very

short lives, still yields mean, median and mode values of approximately 55-60 years. 94 27 There is no logical explanation or documentation presented by the Company that 28 *94 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 retaining the unusually low values in Mr. Spanos' database, the mean, median and mode would all be in the upper 30 to 40 year range, or more in line with the existing ASL. Some minimal increase in the ASL above the 31-year ASL (that is as good a fit to the historical data as is the Company's proposal) is warranted in light of industry data, the Company's inappropriate historical actions of overloading transformers, the existing ASL, and the inclusion of hurricane activity in the historical data. Therefore, I am

I 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 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 files its next depreciation study. *96 database of approximately 60 values. The only few values that are lower correspond to a

17 Canadian utility, a cooperative and a utility that has not had its proposed ASL tested in a 18

fully litigated proceeding. 100 Moreover, the historical data relied upon by Mr. Spanos 19 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?

24 A. I 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 25

standpoint, but also from the standpoint of the unusual "L4" dispersion pattern. Mr. 26 27 Spanos' database of other utilities indicates a 40-45 year ASL is indicative of average *97 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- year ASL. Such a value still leaves the Company at the very low end of the industry 20 range, well below industry averages, and the existing ASL. I also recommended a "R3" 21 Iowa Survivor Curve, which corresponds to the most frequently used curve in Mr. 22 Spanos' database. In conjunction with my ASL recommendation, I further request that 23

I the Commission order the Company to provide a detailed analysis as to why its historical 24 database gives indications of artificially short ASLs and what portion of such lower ASLs 25

I 26 is due to the inclusion of recent hurricane related activity. *98 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

warehouse that is owned rather than leased. ETI owns most of its buildings. ^[107] 20 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 noted that a dramatic decline in the OL T as set forth on Exhibit JJS-1 page 176 is a result 24 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 *99 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? A. My recommended 53-R2 life-curve combination results in a $299,763 reduction to

depreciation expense based on plant as of December 31, 2008. Account 391.2 Q. WHAT DOES THE COMP ANY PROPOSE FOR ACCOUNT 391.2 - GENERAL

INFORMATION SYSTEMS?

The Company proposes a 5-SQ life-curve combination, or a 5-year amortization A. period. ^[111]

I

*100 Another consideration that recognizes the understatement of amortization period is Mr. Spanos' reference to the period during which the asset will "render most of their service." Service life or amortization period is not intended to capture "most" of the service life of an asset, but the entire service life of the asset. Even if the "most" standard were appropriate, Mr. Spanos has understated the reasonable amortization period for the majority of the expected life. In addition, my recommend I 0-year amortization period is consistent with what is the existing rate approved by the Commission in Docket No. 16705. Mr. Spanos' proposal cuts the existing IO-year amortization period in half. It is therefore inappropriate from the standpoint of his stated basis. In addition, review of Mr. Spanos' industry database further supports the use of the IO-year amortization period rather than the proposed 5-year amortization period. In fact, the majority of the values reported for information software systems in Mr. Spanos' database are IO years. No

*101 18 Q.

WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL?

19 A. The Company's basis is the same as identified as above for Account 391.2. 20 21 Q. DO YOU AGREE WITH THE COMP ANY'S PROPOSAL? 22 A. No. The Company's amortization period is artificially short. Therefore, I recommend a 23 20-year amortization period for the investment in this account. First, it must be noted that the existing depreciation life for the investment in this account is 20 years. Thus, Mr. 24 25 Spanos obviously did not rely on this particular item of information for his judgmental 26 approach even though it is one of the stated bases. Next, the investment in this account is 27 at the point of reaching the 15-year proposed amortization period, thus ifthe amortization 28 period is not extended the Company would be recovering through base rates a fully

recovered investment that has not been retired. 116 29 *102 17 18 Account 397.1 19 20 Q.

WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 397.1 - GENERAL

COMMUNICATION EQUIPMENT? 21 The Company proposes a 10-year amortization. ^[118] 22 A. 23 24 Q.

WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL?

The Company's basis for this account is identical as to that noted for Account 391.2. 25 A. *103 based on plant as of December 31, 2008. The resulting amortization remaining life rate 18 for the investment is 5. 72%. 19 20 21 Account 397.2 22

Q.

WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 397.2-GENERAL 23 24 COMMUNICATIONS EQUIPMENT-MICRO WA VE?

The Company proposes a 15-year amortization period. 122 25 A. 26

~ Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 27 28 A. The Company's basis is the same as previously stated for Account 391.2.

*104 Finally, the most important aspect of the need for a longer amortization period is the fact that almost half of the investment in this account is already fully accrued using a 15-year amortization period. ^[124] The Company has substantial levels of investment that was placed in service back in 1983 through 1985. In addition, substantial levels of additional investment are at the point where they will become fully accrued (a form of accelerated depreciation) if the 15-year amortization period is adopted. Therefore, I recommend a minimum 20-year amortization period. In addition, I recommend that the Commission order the Company to correct its reserve associated with any account that is fully accrued and recognize the additional depreciation or amortization that should have been booked. The Company's failure to comply with normal regulatory requirements to continue to apply approved depreciation rates to all gross plant in service is inappropriate. The

*105 17 Q. WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL? The Company claims to have relied upon a 5-year historical database for its analyses. 125 18 A. 19 Mr. Spanos claims he performed his analysis "based on common depreciation accounting

practices and judgment." ^[126] Mr. Spanos further stated that for many of the accounts, the 20 21 analyses of the 5 years of historical data did not produce conclusive results, therefore

judgment and industry averages were a major factor for those accounts. ^[127] Mr. Spanos 22 23 admits that for approximately 60% of the depreciable plant he based his proposal on

judgment and comparison with other utility information. ^[128] 24 *106 17 18 opposite and ignored the Company's actual historical data and relied on industry data for

what he viewed as appropriate. ^[132] Thus, we are left with a very generalized stated criteria, 19 a less than explanative or supported example, and then inconsistent actions with no 20 explanation. This leaves a situation where the Company has presented nothing of 21 substance as the basis for its mass property net salvage proposals. 22 23 24 Q.

IS THE 5-YEAR DATABASE RELIED UPON BY MR. SPANOS ADEQUATE TO

ESTABLISH A REASONABLE INDICATION OF WHAT MIGHT OCCUR IN 25 THE FUTURE? 26 No. First it must be emphasized that the 5-year period Mr. Spanos relied on is an 27 A. exceptionally short timeframe for performing a historical analysis for net salvage 28 ^[129] Exhibit JJS-1 pages 37 and 38. ^[130] Id., at page 38. ^[131] Id. ^[132] Depreciation of Mr. Spanos on April 20, 2010 at TR 125-126.

72 I purposes. Indeed, Mr. Spanos ·relied on a 16-year period for his identical analysis in the El Paso Electric case filed at the same time before this Commission. Moreover, reliance on only a 5-year database for this type of analysis is anything but a "common depreciation accounting practice" as claimed by Mr. Spanos. Next, Mr. Spanos recognizes that the limited historical database is skewed due to results of storms that forced higher labor costs. What Mr. Spanos glossed over is that these referenced storms are major hurricanes. Indeed, on September 24, 2005 Hurricane Rita hit the area with 120 mile per hour winds. On September 13, 2007, Hurricane Humberto hit the area with 85 mile per hour winds. Then on September 13, 2008 Hurricane Ike hit the Texas coast with 110 mile per hour winds. 133 Thus, in the 5-year period relied upon for indications of the future, the area was hit with at least 3 hurricanes, two of which would be categorized as severe. This compares to only 7 hurricanes hitting the Texas coast at or east of Galveston during the past 38 years. 134 That represents only one hurricane every 5.4 years during the past 38 years compared to Mr. Spanos' database, which reflects such an occurrence once every 1. 7 years. This represents an extremely skewed database. Next, due to the fact that cost of removal and gross salvage may be recorded many years after a retirement is *107 recorded, the lack of time synchronization further diminishes the value of a short 5-year database. In addition, it turns out the database relied upon and presented by account does not reflect actual information by account. Only through repeated attempts during discovery was it determined that the account-specific 5-year data relied upon and presented by Mr. Spanos in his 2008 Study represented an unsubstantiated allocation of net salvage values from the functional level. 135 In other words, even in those instances where Mr. Spanos claims to have given some significance to his statistical analysis, the underlying data was not

I maintained by account and thus, cannot be assumed to be representative of the accounts. The Company's database is so flawed not only from the standpoint of timeframe, or the inclusion of major hurricanes, but also in the maintenance of account-specific data. *108 Yes. 138 When Mr. Spanos was requested in discovery to produce the items that affected

18 A.

his judgment in a manner that could be verified, he stated that his judgmental process 19 20 cannot be quantified and therefore provided nothing. Indeed, Mr. Spanos stated that

''there's no log that basically defines what's in my head." 139 21 22

DOES

MR. SPANOS PERFORM A NUMBER OF DEPRECIATION STUDIES 23 Q. ANNUALLY? 24

Yes. During Mr. Spanos' deposition, he claimed that he performs about 20 depreciation 25 A. studies per year for the past 24 years. ^[140] Given that most utilities have dozens of plant 26 27 accounts means that the amount of detailed information that Mr. Spanos claims to 28 maintain in his head would be quite improbable. *109 17 SUPPORT FOR THE COMP ANY'S NET SALVAGE PROPOSALS? 18 A. No. First, it must be noted that the site visit notes are rather cryptic, at best. Even when 19 the.re are items of information noted, there is no underlying support for any claim. As of 20 this time, the Company has still not provided any underlying support for any of the 21 claims referenced in Mr. Spanos' site visit notes. Moreover, there is generally no 22 connection identified as to how any item of information affected the decision making 23 process for each account. This connection apparently resides only in Mr. Spanos' head 24 and cannot be quantified except when Mr. Spanos actually developed his various 25 proposals. 26 27 Q.

PLEASE SUMMARIZE THE COMP ANY'S PRESENTATION.

There are many serious flaws with the Company's presentation for its mass property net 28 A. salvage proposals. The time frame is too short, the data has been manipulated, the data 29

*110 of 10 years for its next depreciation study. In addition, the Commission should order the Company to actually present information substantiating its proposals on an account by account basis, including underlying support and documentation and order that the Company's books be maintained in that manner on a going forward basis.

Q. WHAT IS THE IMP ACT OF YOUR RECOMMENDATION? A. The standalone impact of my recommendation results in a $10.6 million reduction to

annual depreciation expense based on plant in service as of December 31, 2008. 7. ELG vs. ALG Calculation Procedure Q. WHAT IS THE PURPOSE OF TIDS PORTION OF YOUR TESTIMONY? A. This portion of my testimony addresses the Company's decision to employ the

depreciation calculation procedure identified as the ELG procedure. 76 1 Q.

WHAT DO YOU RECOMMEND?

2 A. For various reasons, including the change in the underlying data, I recommend reliance on the industry standard ALG calculation procedure. 3 4 5 Q.

HAS TIDS COMMISSION IDSTORICALLY RELIED ON THE ALG

PROCEDURE? 6 7 A. Yes, with the exception of adopting ELG for a limited number of accounts in ETI' s last fully litigated case, Docket No. 16705. For example, in PUC Docket No. 14965 Finding 8 of Fact 95 states that "CPL's depreciation rate should be set using the average life group 9

10 ("ALG") procedure." This is the typical calculation procedure that I am aware of that has been employed by the Commission in all prior proceedings. Given the change in the 11 12 underlying data for ETI, even the prior limited acceptance of ELG by the Commission in 13 Docket No. 16705, which was based on superior data, is no longer valid. 14 15 Q. DOES MR. SPANOS ATTEMPT TO IDENTIFY THE DIFFERENCE IN 16 CALCULATION PROCEDURES BETWEEN THE ELG AND ALG

*111 PROCEDURE IN ms TESTIMONY? 17 18 A. Yes. Beginning on page 23 and continuing through 27 of Mr. Spanos' testimony, he 19 provides information comparing ELG and ALG depreciation procedures. I do not agree 20 with certain aspects of Mr. Spanos' presentation. These differences will be discussed later 21 and in Appendix B. 22 23 Q.

CAN YOU BRIEFLY STATE WHY THE ELG PROCEDURE

IS I 24

INAPPROPRIATE FOR UTILITY RATEMAKING PURPOSES?

Yes. The ALG procedure calculates the remaining life on an average investment basis, 25 A. knowing that the projection will not be accurate for each vintage of additions and every 26 27 item of plant added within each vintage. Alternatively, the ELG procedure, which also 28 relies on the same less than perfect data and the same assumptions to derive the ASL and 29 dispersion curve, culminates with a calculation of the remaining life that assume that 30 every future year level of retirement is known with absolute precision for as much as 100 31 years into the future. Such a concept of absolute precision when forecasting is illogical on

77 its face in the real world of utility operation, and would only be more accurate than the ALG procedure under the infinitesimally small possibility that future events on an annual basis will actually follow a precisely defined pattern, each and every year for the next 50 to 100 years. Simply put, the ALG procedure recognizes and reflects reality, while the ELG procedure clings to the presumption of unobtainable theoretical precision. I submit that the probability of that occurring is so remote as to be nonexistent.

Q. SETTING ASIDE THE TECHNICAL DISCUSSION OF ELG VERSUS ALG FOR NOW, CAN YOU PROVIDE AN EXAMPLE OF THE IMPACT BETWEEN THE TWO PROCEDURES?

A. Yes. The remaining life for individual vintage can be compared between the ELG and the ALG procedures when the same ASL and corresponding dispersion curve are employed. For example, for Account 353 - Transmission Station Equipment, Mr. Spanos has proposed a 45-R2.5 life-curve combination. Logically, one would normally assume that brand new plant added into service at mid-year with an expected overall 45-year ASL would have approximately a 44.5-year (45-0.5) remaining life at the end of the first year. *112 The precise value at the end of the first year for the 45-R2.5 life-curve combination is 44.53 years under an ALG procedure. However, review of the 2008 vintage addition for ETI identifies a remaining life that is nowhere near the 45-year value for new plant in service at the end of the first year. In fact, Mr. Spanos assigned the 2008 vintage addition a 33.17-year remaining life due to his use of the ELG procedure. In other words, under the ALG process, a 2008 vintage addition has a remaining life approximately 99% (44.5/45) of the ASL when first placed into service, while the same 2008 vintage addition has a remaining life of only 73.7% (33.17/45) of the ASL under the ELG procedure. Approximately one-fourth of the remaining life for the newest vintages is eliminated under the accelerated depreciation calculation of ELG, when compared to the ALG procedure. It is this dramatic difference that is created by the acceleration caused by the ELG calculation procedure that appeals to utilities that seek accelerated capital recovery. Indeed, the overall ELG remaining life for Account 353 is 25.63 years, while the ALG remaining life for the same data is 31.05 years, or 21 % higher. The artificially short ELG

78 remaining life increases annual depreciation expense for this single account by 2 approximately $1.8 million. 3 4 Q. HAVE YOU TESTED THE RELATIONSHIP BETWEEN ACTUAL 5 RETIREMENT ACTIVITY FOR TRANSMISSION ACCOUNT 353 DURING 6 THE PAST 5 YEARS COMPARED TO WHAT WOULD BE ASSUMED 7 THROUGH THE ELG PROCEDURE? 8 A. Yes. In order to demonstrate the false premise relied upon by Mr. Spanos regarding the 9 theoretical precision of the ELG procedure; I tested the ELG proposed relationships

10 against reality for the largest mass property account for the past 5 years. Transmission 11 Account 353 is the largest mass property account and reflects over $370 million of 12 investment as of December 31, 2008. Based on Mr. Spanos' assumed 45-R2.5 life-curve 13 combination, and testing such proposal on an ELG basis for the most recent 5 years 14 (2004-2008), one finds a dramatic difference between the assumed precision in the ELG 15 procedure and actual events. The table below identifies the expected ELG retirement 16 amounts by year for each vintage addition for the years 2004-2008. There are 15 *113 17 expected levels of retirement activity, beginning with 5 values for the 2004 additions,

I 18 then 4 values for the 2005 addition, down to only one value for the 2008 addition. ELG EXPECTED RETIREMENTS BY VINTAGE ADDITION 2008 2007 2006 2005 2004 Year Addition 2008 $10,225,616 $6,283 $7,404,974 $9,791 2007 $4,550 2006 $25 '7 44,244 $37,100 $34,040 $15,818 2005 $20,005,825 $31,409 $28,831 $26,452 $12,292 $6,979,660 2004 $12.021 $10.958 $10.058 $9.229 $4.289 $96,604 $52,329 $21,521 $4,289 Total $78,378

19 The following table reflects the actual retirement activity for the vintage additions for the 20 years 2004-2008 and sets forth the errors between the actual retirement activity and what 21 Mr. Spanos' ELG procedure would have assumed.

79 l ACTUAL RETIREMENTS BY VINTAGE BY YEAR Year 2008 2007 2006 2005 2004 2008 $0.00 $0.00 $0.00 2007 $187.08 2006 $0.00 $0.00 2005 $15,447.35 $0.00 $0.00 $0.00 2004 $0.00 $12.014.15 $0.00 $0.00 $0.00 Total $15,634.43 $12,014.15 $0.00 $0.00 $0.00 ELG Expected $96,604.05 $78,378.39 $52,329.05 $21,521.10 $4,288.58 ELG Error-$ $80,969.62 $66,364.24 $52,329.05 $21,521.10 $4,288.58 83.8% 84.7% 100.0% ELG Error-% 100.0% 100.0%

2 As can be seen, there are only 3 retirement values out of the potential of 15 values that 3 should have occurred had ELG been an accurate estimator. Moreover, one of the three 4 values that did occur is only a $187.08 at a point in time where the ELG procedure would 5 have expected $37,100 of retirement activity. A review of the data for the largest single 6 account as set forth in the two tables above clearly demonstrates that there is no 7 reasonable precision between the ELG calculation procedure and actual transactions. In *114 8 fact, for the 5-year period analyzed, the ELG procedure predicted a total of $253,121 of retirements, while only $27 ,648 of actual retirements occurred, or only 11 % of the 9 10 expected total. This is precisely why the theory of ELG fails in any attempt to mirror the 11 real world of utility operations. 12

13 Q. ABOVE AND BEYOND THE PRACTICAL FALLACIES OF THE ELG

14 PROCEDURE, ARE THERE SPECIFIC PROBLEMS WITH THE COMP ANY'S 15 ELG CALCULATIONS? Yes. Mr. Spanos' calculation of ELG values is incorrect. Indeed, Mr. Spanos admits that 16 A.

there appears to be an "anomaly" in his calculations. 143 There is no life-curve 17 18 combination that could be used in an ELG calculation procedure that would yield any 19 reasonable level of accuracy for the 5-year example above. *115 17 in that remaining lives are increasing for older plant addition, but Mr. Spanos' calculation

I 18 yields a second theoretical impossibility by increasing - then decreasing - then again increasing the remaining life as older vintages are analyzed. The remaining life 19 20 calculation should be a continuous movement in one direction (lower remaining lives for 21 older vintages) and would not, unless there were an error, increase or change directions 22 multiple times.

i44Id. 81

ELG REMAINING LIVES FOR ACCOUNT 365

Vintage Remaining Year Life Difference 1998 21.65 (0.10) 1999 21.75 0.04 2000 (0.03) 21.71 2001 21.74 0.15 2002 21.59 0.21 2003 21.38 0.31 2004 21.07 0.53 2005 20.54 0.82 2006 19.72 1.34 2007 18.38 3.25 2008 15.13

2 Q.

CAN THE COMMISSION RELY ON MR. SPANOS' ELG PRESENTATION

EVEN IF IT HAD AN INCLINATION TO ACCEPT AN ELG CALCULATION? 3 4 A. No. Even if the Commission had an inclination to accept the ELG procedure, it cannot do *116 5 so because of the inaccurate calculations reflected in the Company's presentation. Simply 6 put, not only is the theory underlying the ELG procedure inappropriate in the real world 7 of utility operations, but also the quantification of ELG results is faulty, thus rendering 8 the Company's ELG presentation in this proceeding fatally flawed and lacking any 9 credibility. 10 11 Q. HAS MR. SPANOS ATTEMPTED TO REVOKE ms USE OF THE WORD

ANOMALY IN REFERENCE TO ms CALCULATION PROCEDURE? 12 Yes. In response to Rose City 24-38, Mr. Spanos attempts to claim that his use of the 13 A. 14 word anomaly was not a reference to an error in his program. Mr. Spanos attempts to 15 divert attention from his theoretically impossible results by: (1) indicating that the anomaly might be associated with the mid-year convention; (2) discussing the composite 16 17 remaining life calculation rather than the vintage remaining life values; and (3) claiming 18 the vintage remaining life is calculated by dividing the future accruals by the annual 19 accruals by vintage. In other words, he claims that the remaining life is not a function of 20 the ASL and dispersion pattern combination, but rather a calculation of dividing future

82 1 accrual values by annual accruals. Mr. Spanos concludes his response by claiming that 2 the 2008 vintage remaining life being shorter than the 2007 vintage remaining life "is not 3 truly an anomaly, but a refinement of the annualized rate." 4 5 Q.

IS THERE ANY VALIDITY TO MR. SP ANOS' CLAIM REGARDING THE MID

YEAR CONVENTION AS A BASIS FOR ms ANOMALY-REFINEMENT?

6

7 A.

No. As noted in the table above for Account 365 and as reflected in numerous accounts, 8 the anomaly-refinement occurs for many vintages including the most current vintage to 9 which Mr. Spanos claims the half-year convention has an additional impact. The half-

10 year impact for the most current vintage is already addressed when an ASL and 11 corresponding dispersion pattern are selected. Simply put, Mr. Spanos' reference to the 12 half-year convention is misleading and disingenuous. 13 14 Q. DOES MR. SP ANOS' DISCUSSION OF THE COMPOSITE REMAINING LIFE

CALCULATION SHED ANY LIGHT ON ms CLAIMED ANOMALY- 15 *117 16 REFINEMENT? 17 A. No. Again, his reference to the composite remaining life is an attempted diversion from

the real issue, which is his claimed anomaly-refinement associated with individual vintage remaining lives. It is theoretically impossible to have increasing remaining lives for older vintages. The vintage remaining life calculation is the issue at hand, not the composite remaining life. Mr. Spanos is well aware of the distinction and thus, his data response represents yet another distortion.

Q.

IS THERE ANY BASIS IN MR. SPANOS' CLAIM THAT THE VINTAGE REMAINING LIFE IS CALCULATED BY DIVIDING THE FUTURE ACCRUALS BY THE ANNUAL ACCRUALS BY VINTAGE?

A. No. The vintage remaining lives are a function of the ASL and the corresponding dispersion pattern. The vintage remaining lives are used to develop the annual accruals by vintage. This process is accomplished by taking the future accruals (the total amount still remaining to be recovered) and dividing it by the vintage remaining life, in order to obtain the annual accruals by vintage, not the other way around as Mr. Spanos claims.

83 Even if Mr. Spanos did work backwards and developed the annual vintage accruals first, 1 2 he would still need to rely implicitly on the vintage remaining lives derived from the 3 proposed life-curve combination. All such life-curve combinations must yield declining 4 remaining lives for older vintages unless there is an error. 5 6 Q.

CAN YOU FIND THE IDENTICAL ASL AND DISPERSION PATTERN FOR

7 DIFFERENT ACCOUNTS IN MR. SPANOS' PRESENTATION? 8 A. Yes. For example, Accounts 369.1 and 369.2 - Distribution Overhead and Underground

Services, respectively, have the same ASL and dispersion pattern. ^[145] The original cost, 9 10 calculated reserve, allocated book reserves and future accruals are different for every 11 single vintage between the two accounts. The one thing that is constant, since it is derived 12 from the same ASL and dispersion pattern, are the vintage remaining lives. In fact, they 13 are identical down to the hundredth of a decimal place as would be expected as they are 14 derived from the same ASL and dispersion pattern. IfMr. Spanos would have us believe 15 that the remaining life factors were not derived from the ASL and corresponding

*118 dispersion pattern, but rather by taking the resulting annual accruals by vintage and dividing those into the future book accruals by vintage and thus, deriving the remaining life, then the potential of coincidence that they would produce the identical remaining life values by vintage to one hundredth of a percent value would be astronomical. Thus, Mr. Spanos' own depreciation study clearly refutes his claim.

Q. IS THERE YET ANOTHER COMBINATION OF ACCOUNTS FOR WHICH MR. SPANOS PROPOSES THE SAME ASL AND DISPERSION PATTERN?

A. Yes. Mr. Spanos proposed the same 40-S0.5 for distribution Account 364 - Poles, Towers and Fixtures, as well as Account 373.2 - Non-Roadway Lighting. 146 Due to the unusual manner in which Mr. Spanos' procedure artificially limits the allocation of book I reserve to a maximum of the original cost less net salvage, Account 373.2 only reflects one vintage remaining life, that being for the 2008 vintage. However, that vintage remaining life for Account 3 72.2 is, again, identical to the corresponding 2008 vintage

I

*119 16 17 Q.

WHAT DO YOU RECOMMEND?

I recommend the utilization of the standard industry practice of the ALG calculation 18 A. 19 procedure. The ALG procedure is consistent with the overall process of depreciation, 20 which is based on analysis of numerous averages or broad brush approaches, recognizing 21 that historical indications and other information will only provide, at best, a reasonable 22 indication of what may transpire in the future on average. There will always be errors 23 between future projections and what actually transpires on an annual basis in the future; 24 however, the ALG procedure minimizes such error, while the ELG procedure maximizes 25 such error. Moreover, the ALG procedure is a standard straight-line approach, while the 26 ELG procedure represents an acceleration of capital recovery when compared to the 27 standard industry approach. *120 16 17 Q.

WHAT DO YOU RECOMMEND?

18 A. I recommend relying on the industry standard remaining life calculation. 19 20 Q. DOES MR. SPANOS CLAIM THAT HE IS NOT PROPOSING A CHANGE 21 FROM THE REMAINING LIFE METHOD OF DEPRECIATION? 22 A. Yes. Mr. Spanos states that on page 13 of his direct testimony. However, what he fails to note is that the remaining life method he employs is different from the remaining life 23 24 previously used and employed by basically all other utilities and depreciation consultants 25 other than those utilities for which Gannett Fleming performs depreciation analyses. In 26 other words, using the identical data the remaining life calculation process previously 27 employed by the Company would produce a different remaining life in every instance 28 when compared to the new remaining life calculation process proposed by Gannett 29 Fleming.

86 Q. WHAT IS THE DIFFERENCE BETWEEN THE STANDARD REMAINING LIFE 2 CALCULATION AND THE NEW CALCULATION PROPOSED BY GANNETT 3 FLEMING?

4 A.

Gannett Fleming incorporates the impact of net salvage into the remaining life calculation. Thus, a change in the net salvage will result in a change to the composite remaining life for an account. This is illogical and inappropriate on its face. Gannett Fleming's approach allocates the book reserve to individual vintage additions, but not on a consistent basis. Gannett Fleming further deviates from the standard approach by capping the level of accrued depreciation to the maximum level of the original cost plus the impact of net salvage. Thus, a plant account that has a 5-year ASL assigned to it, but has plant in service still at an age of 15 years would not reflect the over-depreciation that occurred during the additional 10 years of service. Gannett Fleming's approach artificially caps the level of reserve assigned to a vintage and spreads the balance to other vintages. Given that Gannett Fleming's approach relies on a dollar

*121 16 weighting of remaining life by vintage, that approach modifies the results of the standard 17 remaining life calculation. 18 19 Q.

HAS TIDS ISSUE BEEN LITIGATED RECENTLY?

20 A. Yes. In a recent case in Florida in which the decision was rendered at the beginning of 21 2010, the FPSC stated in its order for the FPL that: 22 23 For the reasons explained below, we are of the opinion that FPL's calculation 24 of remaining life leads to questionable results. Accordingly, we approve of 25 remaining life calculation based on using the average age of the given 26 account, with the selected survivor curve. The remaining lives we approve below are based on this calculation. 27 28 *** 29 We do not agree with FPL that its remaining life calculation is consistent with

I 30 FPL' s actual practice. FPL does not maintain its plant account reserves be 31 vintage; they are maintained on a total account basis. Also, depreciation rates 32 are not applied to individual vintages; the rates are applied to the total account

I 33 balance. Allocating the book reserve to individual vintages based on a theoretical reserve calculation is not necessarily a concern. However, in its 34 allocation, FPL determined that the reserve for any given vintage could not 35

I 87 exceed the survivors for that vintage less net salvage. For example, in reviewing the calculation presented for Account 396. l, Power Operated Equipment, no reserve was allocated to the 1986-2000 vintages because the allocation of the reserve indicated that these vintages were fully accrued. That is because the most allocated to any given vintage was the surviving investment for that vintage less net salvage. These vintages represent more than 36 percent of the plant account investment. We believe this is a significant amount of investment that has no remaining life. Looking at Account 396.8, Other Power Operated Equipment, FPL uses an L0.5 Iowa curve and 9-year life combination. The average age of the account is 7.5 years. Using the method endorses by OPC, the remaining life of the account is 5.2 years, compared to the Company's calculation of zero. While this account has an existing reserve surplus, that should not deter from the fact that it does indeed have a remaining life using FPL's proposed curve and life combination. FPL did not dispute that net salvage impacts its calculation of remaining life. Net salvage impacts the remaining life depreciation rate, not the average remaining life itself. ^[148] Unfortunately, because FPL's calculation assumes that no vintage can have more reserve allocated than the surviving investment less net salvage, as net salvage varies, so does the remaining life. For all the foregoing reasons. FPL' s remaining life calculation leads to questionable *122 results. Accordingly, the remaining lives we address below are calculated by applying the average age of the account to the selected survivor curve. This is similar to OPC's calculation of remaining life and PEF's calculation in its depreciation study in Docket No. 090079-EI. The remaining lives we approve below use this calculation. 149

In other words, after a fully litigated analysis of the remaining life calculation, the FPSC found that it could not rely on Gannett Fleming's remaining life calculation since it produces questionable results and is affected by changes in net salvage.

Q. WHAT DO YOU RECOMMEND? A. In each instance where I have recommended a change in the life or dispersion pattern for

a mass property account or where I have proposed an ALG calculation procedure, I have employed the standard remaining life calculation that all other depreciation consultants employ other than Gannett Fleming. My calculation is the same calculation that the Company previously employed prior to retaining Gannett Fleming. *123 A. The adoption of depreciation or amortization rates rests solely with the regulator, not with the Company. This regulatory principal is essential in order to protect customers from inappropriate action that a utility might take. For example, if a utility had the unilateral right to change its depreciation rates as desired, it would be in the best interest of the utility's shareholders to immediately reduce or cease the booking of depreciation expense after the end of a rate case. If such practice were allowed, the utility would still recover the depreciation related revenue requirement level built in base rates, but customers would not receive the benefit expected with the payment of depreciation expense over time. The benefit customers receive for depreciation expenses is an offset to rate base for

I the utility's recovery of its invested capital. The benefit of depreciation expense is booked into Account 108, the accumulated provision for depreciation ("APFD"). The

I APFD is subtracted from gross plant in order to determine net plant. Net plant is the largest component of rate base.

I 89 I 1 Q.

HOW IS THE DEPRECIATION PROCESS PROPERLY PERFORMED BY A

UTILITY? 2 3 A. Once a depreciation rate is adopted by a regulator, that rate should be applied to gross 4 plant in service on a monthly basis until the plant retires. 5 6 Q. DOES THE COMP ANY FOLLOW TIDS FORMAT? No. The Company's policy is that once it makes a unilateral decision that it believes an 7 A. 8 account has become fully accrued, it ceases the booking of depreciation expense to the

APFD. 150 Thus, by not continuing the booking of depreciation expense, ETI has changed 9 10 the applicable depreciation rate to zero (0) rather than whatever rate the Commission 11 previously adopted. The unilateral decision to cease the booking of depreciation expense 12 is made even though the plant has not retired. 13 14 Q. WHAT IS ETl'S STANDARD FOR ASSUMING A PLANT HAS BECOME FULLY ACCRUED? 15 *124 When the Company "believes" it has recovered the total investment plus the impact of its 16 A.

estimate of net salvage, it ceases the booking of depreciation expense. Thus, the standard employed by ETI is its unilateral "belief."

Q. WHAT IS THE IMP ACT OF TIDS INAPPROPRIATE UNILATERAL ACTION? A. By ceasing the booking of depreciation expense, the Company understates the APFD and thus on a going forward basis overstates rate base since the APFD is artificially not permitted to increase. Moreover, this inappropriate practice deprives customers of the return of their overpayment of depreciation expense through the remaining life depreciation technique.

Q. WHAT IS THE REMAINING LIFE DEPRECIATION TECHNIQUE? 28 A. As set forth under the General section of my testimony on depreciation, the remaining 29 life technique attempts to recover the net depreciable investment less net salvage over the 30 remaining expected life of the account. The remaining net depreciable investment less net *125 16 A. The Company stated that its software program, PowerPlant, has a built-in algorithm that 17 automatically stops depreciation when a particular depreciation group is fully

depreciated. ^[153] The Company implemented this specialized software in January 2004. ^[154] 18 19 It appears that prior to the implementation of this software progress this situation did not 20 exist. 21 22 Q. HOW DOES THE COMP ANY JUSTIFY ITS ACTIONS? 23 A. The Company claims that depreciation is the loss of service value, as set forth in the

USOA. ^[155] The Company believes that the definition of service value limits depreciation ~

24

to the original cost less net salvage. ^[156] 25

I

*126 captive customers would be forced to pay depreciation expense through rates approved 16 by the Commission without getting the benefit of the depreciation being added to the 17 accumulated reserve. Therefore, the Company's proposal must be rejected. 18 19 20 Q. WHAT DO YOU RECOMMEND? 21 A. I recommend that the Commission recognize the amount of loss in back depreciation expense that should have been booked to the accumulated provision for depreciation 22 associated with three accounts referenced by the Company. As set forth on Schedule (JP- 23 24 2), the amount of additional depreciation expense that should have been recognized on 25 the Company's books and records through the end of the test-year in this case is 26 $6,160,578. I further recommend that the Commission order the Company to correct the 27 algorithm in its software system so as to comply with the booking of Commission 28 approved depreciation ate.

is1 Id. 92 l Q. HOW SHOULD THE COMMISSION TREAT THIS AMOUNT? 2 A. The Commission should reduce rate base by the $6,160,578 amount noted above and 3 amortize such amounts back to customers over a 4-year period. This would result in an 4 additional $1,540,145 reduction in annual revenue requirements. 5 SECTION IV: SGSF CAPITAL RECOVERY 6 7 Q. WHAT IS THE ISSUE IN THIS PORTION OF YOUR TESTIMONY? 8 A. In this portion of my testimony I discuss the Company's acquisition of the Spindletop 9 Gas Storage Facility ("SGSF") and two key resulting issues. The first issue is the

10 recognition of the substantial positive net salvage identified by ETI. The second issue is 11 the correction of the excess recovery of investment on an accelerated basis. 12 13 Q. WHAT DO YOU RECOMMEND? *127 A. Given the unusual facts and circumstances surrounding the construction, financing,

capital payments, rate treatment, admission by the Company that these are customer savings rather than shareholder profits, and the exercise of the purchase option, I recommend that: (1) current customers be reimbursed for their equitable right to the current net depreciable value, and (2) current customers receive a credit for the $40 million of return of capital (i.e., depreciation) they have paid during the 1990s and early 2000s due to the special rate treatment granted the Company and that such credit be amortized to current customers over a four-year period. Given that Cities' witness Mr. Nalepa recommends the removal of all SGSF costs, the second above noted recommendation is necessary in the event the Commission elects not to adopt Mr. Nalepa's recommendation. In any event, the need to recognize the net salvage or sale value is still required.

Q. PLEASE PROVIDE THE BACKGROUND ASSOCIATED WITH THIS PARTICULAR ISSUE. In the late 1980s and early 1990s, the Company's predecessor GSU was in a difficult

A. financial position. An opportunity arose where GSU could obtain a gas storage facility 93 1 for the benefit of customers. Unfortunately, due to its financial constraints, GSU could 2 not purchase and construct the gas storage facility. It contracted with Sabine Gas 3 Transportation Company ("SGT") to construct the facility and utilize it at the direction of 4 GSU. GSU retained control of construction, modifications, and operation of the facility. 5 In addition, the operating agreement included an option to purchase the facility from SGT 6 at a "Payoff Amount". The "Payoff Amount" reflected a reduced net cost in association

with the level of "Credit Payments" made by the Company. 158 The "Credit Payments" 7 8 were costs the Commission allowed the Company to pass on to customers. In 2004, the 9 Company exercised its purchase option and became the owner of the gas storage facility

10 for a $1.00 payment. 11 12 Q. HA VE SGSF CAPITAL COSTS BEEN INCLUDED IN ELIGIBLE FUEL SINCE ITS INCEPTION? 13 14 A. Yes. In Docket No. l 0894, the Commission found that the "Credit Payments" to SGT for

*128 capital reduction were costs that were passed on to customers. 159 Q. WHAT IS THE VALUE OF THE FACILITY? A. Recently, the Company has appraised the value of the gas storage facility at $100 million. 160 In other words, the current best estimate of the value of SGSF is $100,000,000 less the $1 it paid for the facility. Q. ARE THERE OTHER EVENTS CURRENTLY TRANSPIRING THAT IMPACT

THIS PARTICULAR ISSUE?

Yes. As part the electric deregulation process in Texas, a jurisdictional separation has A. been completed. The Company is now a distinct corporate entity, separate from Entergy Gulf States Louisiana. While the ownership of SGSF remains with ETI, the completion of the separation process may result in the sale of the Texas system. In fact, Entergy Corporation chairman and Chief Executive Officer J. Wayne Leonard told shareholders in November 2007 that he might sell the Texas operations if the jurisdictional split were *129 benefit from the facility. The Commission also allowed the pass through of capital costs (i.e., depreciation) on an accelerated basis. The Commission allowed the financing of the facility to be paid within a 10-year period rather than the then-estimated 30-year useful life of the facility. 163 Now, in recognition of the changed circumstances, and the drastic intergenerational inequity that occurred for customers, it is only fair and equitable to level the field for current and future customers due to prior significant overpayment.

Q. WHAT DO YOU RECOMMEND? A. I recommend that with the changed circumstances associated with the purchase of the facility for $1.00 by the Company that: (1) Texas retail customers be credited for their allocable portion of the current $100 million valuation or net salvage, and (2) Texas retail customers be given credit in the APFD for prior payments for the return of capital (i.e., depreciation). These recommendations are conservative in favor of the Company, given that the gas storage facility may very well continue to increase in value. *130 SGSF regulated service, the value should be revisited in future rate cases like other net salvage values are expected to be revisited.

Q. FROM AN EQIDTY STANDPOINT, ARE TEXAS RETAIL CUSTOMERS

ENTITLED TO THE VALUE OF TIDS FACILITY?

A. Yes. There can be no doubt that Texas retail customers have paid their proportionate share of basically all costs associated with this facility. Had GSU not been in a budgetary constraint position when the opportunity arose to acquire the rights to build the gas storage facility customers would have paid significantly lower fuel costs and base rate charges. Historical fuel costs would have been lower since there would have been no "Credit Payments" made to SGT. Moreover, base rates would not have increased on a comparable basis if the original costs had been included in rate base. This result would have occurred since the effective depreciation component of revenue requirements would have essentially been minimal or even a negative value given the estimated gross salvage for the value of the facility would have been subtracted from the original cost. This is standard industry practice since the useful life of the facility would extend beyond the estimated life of the generating facilities that it serves (Sabine and Lewis Creek

96 generating stations). The last unit at the Sabine station is scheduled to retire no sooner than 2029 . 164 Thus, the gas storage facility could be sold at a substantial value above cost.

2 3 4 In addition, in compliance with the benefits-follows-burdens concept adopted by the 5 Texas Supreme Court, the fact that customers have in fact paid for capital costs, operating 6 costs, property taxes, and basically every other cost associated with the facility, entitles

any gain on sale to be assignable to customers. 165 7 8 9 Q.

WHAT IS YOUR UNDERSTANDING OF THE DIRECTION THE COURTS

10 HA VE PROVIDED TO THE COMMISSION REGARDING WHO IS ENTITLED 11 TO THE GAIN INV ALUE OF THE SGSF? 12 A. I have been advised by counsel that the Texas Supreme Court recognized that ''the proper 13 allocation is a complicated one that cannot be resolved simply by reference to who paid

for the property." 166 The court relied in part on the benefits-follows-burdens principal 14 *131 established in the Democratic Central Committee case. 167 The Court, while not requiring the Commission to consider all of the standards set forth in its ruling, nor forbidding it from considering others, listed a number of factors. The Court noted:

In the general case, the gain should be allocated to that group (as between shareholders and ratepayers) that has borne the financial burdens (e.g., depreciation, maintenance, taxes) and risks of the asset sold. In addition to these two general equitable factors, courts have also considered numerous other factors, including whether the asset sold had been included in the rate base over the years, whether the asset was depreciable property, non depreciable property, or a combination of the two types, the impact of the proposed allocation on the financial strength of the utility, the reason for the asset's appreciation (e.g., inflation, a general increase in property values in the area), any advantages enjoyed by the shareholders because of favored treatment accorded the asset, the dividends paid out to the

*132 16 17 Q. WERE CUSTOMERS RESPONSIBL E FOR DEPRECIATION? In effect, yes. While the amounts paid to SGT did not specifically identify depreciation, it 18 A. 19 is an undeniable fact that the "Credit Payments" were for debt service requirements. The 20 principal and interest components of debt service requirements are the equivalent of 21 depreciation and return., respectively for plant afforded base rate treatment. Thus, the 22 principal payment is the equivalent of depreciation, and the interest portion of the debt 23 service payment is the equivalent of return.. Therefore, while not identified specifically as 24 depreciation, customers did pay the equivalent of depreciation for the investment. This 25 fact also demonstrates that the regulatory treatment afforded the Company was more than 26 the equivalent of providing rate base treatment over the entire operating life of the 27 facility. This represents yet another burden carried by customers, not the Company.

98 1 2 Q.

DOES YOUR RECOMMENDED 100% ALLOCATION OF GAIN TO

3 CUSTOMERS TAKE INTO ACCOUNT THE FINANCIAL STRENGTH OF THE 4 COMPANY? 5 A. Yes. While GSU was not in a financial position to construct the facility back in the early 6 1990s, that situation was rectified when GSU merged with Entergy. In fact one of the 7 benefits touted by Entergy in association with its proposed merger at that time was the 8 financial strength that it brought to the GSU system. Moreover, the financial strength of 9 the utility has been enhanced by normal regulatory treatment in rate proceedings as well

10 as very unique and special legislative treatments realized by the Company over the last 11 several years as it pertains to recovery of capacity charges and hurricane damage costs 12 during the period when the Company had been in a base rate freeze. In addition, when 13 the Company was granted fuel reconciliation treatment for the cost associated with the 14 SGSF it was granted favorable rate treatment for this particular asset. Had the Company

*133 been required to place the asset into base rates rather than receiving reconcilable fuel treatment it would have experienced a regulatory lag in recovery of funds and would not have been guaranteed recovery. This regulatory lag was eliminated by the Commission for the Company's use of the SGSF.

Q. IS THE COMP ANY RESPONSIBLE FOR THE INCREASE IN VALUE OF THE

FACILITY OVER THE YEARS?

A. No. The value of the asset has increased due to market forces, not anything implemented by the Company. Q. IN SUMMARY, IS THERE ANY FACTOR THAT YOU'VE IDENTIFIED WHICH WOULD INDICATE THAT THE COMPANY'S SHAREHOLDERS I 26 WERE ENTITLED TO SOME PORTION OF THE GAIN TO BE OBTAINED 27 I FROM THE ULTIMATE DISPOSITION OF TffiS FACILITY? 28 No. Based on every meaningful factor I have been able to identify associated with the 29 A. I 30 construction, financing, operations, etc. of this facility, it has been customers who are responsible for each component. As such, in my opinion it would clearly be in violation 31

I 99 I of the principals set forth by the Supreme Court of Texas if the Company were to be 1 2 afforded any portion of the gain in value of this facility. Moreover, in Docket No. 10894, 3 Company witness Mr. Harrington stated that the savings of the project were for

customers, not shareholders. 168 4 5 6 Q. HOW DO YOU PROPOSE TO RECOGNIZE THE $100 MILLION VALUE FOR TEXAS RETAIL CUSTOMERS? 7 8 A. As of January 2005, the Company took ownership of the facility after purchasing the 9 facility for $1.00. Texas retail customers should be credited with their allocable portion 10 of the $100 million value as of that point in time. As shown on Schedule (JP-3) this 11 results in a $42.5 million credit to the Texas retail jurisdiction. I recommend that the 12 amount be returned to customers over the 35.5-year remaining life I recommended for 13 Sabine 5, or $1,197,183 annually. This amount should be credited whether Mr. Nalepa's 14 recommendation is adopted. *134 15 16 Q. WHY IS IT APPROPRIATE TO CREDIT CUSTOMERS FOR THE SGSF NET 17 SALVAGE VALUE WHETHER THE PUC ADOPTS MR. NALEPA'S 18 RECOMMENDATION? 19 A. Mr. Nalepa's recommendation reflects a prudent business decision regarding the annual 20 benefits versus costs for the SGSF. My recommendation relates to the value that a 21 different owner with a different operating philosophy might have regarding the facility. It 22 is my understanding that Mr. Nalepa's recommendation is based on the changed 23 circumstances relating to reliability issues and annual costs of operation. ETI no longer needs the facility, but that fact does not change the value of the facility to a new owner. 24 25 By analogy, this is no different than a family no longer needing a two-seat sports car once 26 they have children. The fact that a two-seat sports can no longer fit one family's situation 27 does not diminish the value of the car. *135 15 requirements, it is only equitable to recognize such accelerated payments now that the 16 Company has taken formal ownership of the facility. The Texas retail jurisdiction should 17 be allocated its proportional share of the prior accelerated depreciation payments. This

results in a $17 million adjustment to rate base. ^[169] In conjunction with this credit to rate 18 19 base, I also recommend a four-year amortization in order to correct the substantial level

of intergenerational inequity. This will result in a net $3.8 million annual credit. 170 20 21 Q. HAVE OTHER REGULATORS ADOPTED THE CORRECTION OF 22 INTERGENERATIONAL INEQUITY AS YOU ARE RECOMMENDING IN

I 23 TIDSCASE? 24 A. Yes. The FPSC within the past year ordered precisely this treatment I recommend in this

I 25 case. In fact, the FPSC ordered that state's two largest electric utilities to credit their I I

*136 15 future payment will better meet the regulatory matching principle tying the payment by 16 those customers to the benefit of the storage facility being used to provide that generation 17 of customer's electric service. The will be no need for future customers to pay for the 18 $42.5 million portion of my recommendation given that value will be provided through 19 the sale of the facility after it is retired from utility service. 20 SECTION V: STORM INSURANCE RESERVE 1. General 21 22 23 Q.

WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY?

The Company requests an insurance reserve storm cost accrual of $9,450,000. 172 This

24 A. 25 request is comprised of two components. The first component of $4,180,000 relates to 26 recovering the Company's claimed $64.4 million deficit in its insurance reserve, plus

building the storm reserve to a positive $19 .3 million target. 173 The Company proposes to 27 *137 15 storm to $500,000 per storm.

Rate Base Impact I ETI Cities Adjustment $47,497,395 ($16,857,757) Reserve Deficiency $64,355,152 Reserve Target $19,304,000 $15,572,000 ($3,732,000) $83,659,152 $63,069,395 ($20,589, 757) Subtotal ~ ($25,278,210) Hurricane Proforma $25,278,210 ($45,867,967) Total Rate Base $108,937,362 $63,069,395

Annual Accrual Imnact Rate Base Amortization $4,182,958 $3,153,470 ($1,029,488) $5,270,000 $3,651,320 ($1,618,680) Annual Loss Accrual ~ ($5,055,642) Hurricane Proforma $5,055,642

I

Total Annual Expense $14,508,600 $6,804,790 ($7,703,810)

I

Q.

*138 WHAT DID THE COMMISSION ADOPT REGARDING THE COMPANY'S

SELF-INSURANCE EXPENSE IN DOCKET NO. 16705?

A. The Commission granted the Company $1,651,320 per year for current losses and noted the amount should accrue only enough each year to cover typical storm damage. ^[176] In addition, the Commission did not set a storm reserve balance. The reason the Commission did not set a storm reserve balance is because the Company did not provide a reasonable post test-year level for its then existing reserve fund and because the Company did not prove that the amounts expended in 1997 associated with an ice storm were prudent or appropriate. ^[177]

Q. WAS THE ANNUAL STORM LOSS LEVEL MODIFIED RECENTLY? A. Yes. The Commission recently adopted a settlement in Docket No. 34800 that increased the annual storm loss accrual to $3,651,320 effective January 1, 2009. ^[178] *139 14 2. Storm Reserve Deficit

Q. WHAT DOES THE COMPANY CLAIM AS ITS STORM RESERVE DEFICIT?

The Company claims a $64 million deficit or negative reserve currently. ^[180] A. Q. WHAT IS INCLUDED IN THIS RESERVE THAT CAUSES IT TO BE SO

NEGATIVE? The Company has included all storm-related costs that in aggregate exceeded $50,000 per A. I storm. Some of the costs recognized by the Company included incentive compensation, fire and property insurance premiums, safety training expenses, computer hardware acquisitions, and, in effect, anything else the Company deems appropriate.

Q. DID MR. WILSON DEVELOP THE $64 MILLION RESERVE DEFICIT

VALUE? I No. This amount was provided to him by the Company. ^[181] A. I *140 14 recovered through base rate charges and thus may represent a double recovery of 15 expense. 16 17 Q. AFTER REVIEW OF ALL THE DOCUMENTATION PRESENTED BY THE 18 COMP ANY ASSOCIATED WITH ITS STORM RESERVE, DO YOU BELIEVE 19 ADJUSTMENTS ARE NECESSARY? 20 A. Yes. In my opinion, the Company's claimed $64 million current storm reserve deficiency 21 is quite excessive. In fact, I recommend adjustments to remove the impact of: (1) the 22 major 1997 ice storm; (2) the first $50,000 of each storm corresponding to a deductible 23 that would be in place by standard insurance practices; (3) miscellaneous expenses not 24 appropriately included in the reserve; (4) a proposed situs based adjustment addressed in 25 Docket No. 34800; and (5) additional insurance proceeds associated with securitized 26 storms that have been received or estimated, but which are not reflected in the 27 securitization process or the current filing.

*141 • The Company's line maintenance and vegetation control were reactive in nature and lacked written and specific preventative maintenance policies. Moreover, priority was not given to capital additions to the detriment of adequate maintenance practices. ^[186]

• While the Company claimed that its vegetation management was adequate and consistent with industry practices, extensive evidence was provided to document serious neglect of vegetation management. Such serious neglect resulted in heightened risk to the distribution system associated with the ice storm. "The Commission concludes that the level of the Company's vegetation management is unacceptable and has sipiticantly affected the reliability of the distribution system in recent years." ^[18]

• The Company itself found it necessary to hire 30 new vegetation clearance crews subsequent to the ice storm, which only confirmed the existence of an unacceptable backlog in vegetation control prior to the ice storm. ^[188]

• "The January 1997 ice storm was certainly a severe storm that would have diversely affected the best-maintained distribution system. EGS' distribution system, however, is not the best-maintained. A major cause of the outages during the storm was broken or bowed ice-laden tree limbs overhanging the wires. Tree limbs in ROW overhanging distribution lines pose a threat to system reliability and are largely within EGS' control. The Company's failure to clear the limbs before the storm was a major factor in the number and duration of outages experienced by customers. While the Company's initial efforts to mobilize and *142 Cities point out in their Brief that EGS did not inform the other parties that further charges were made to the fund, and EGS did not update discovery requests advising that the reserve was at a level different from the $11.4 million. Tr. 6928; 6744-6745 (Lawton). The only information concerning post-test-year charges to the reserve appeared in Mr. Wilson's rebuttal. Tr. 8136. On cross-examination, Mr. Wilson testified that he did not know when he first learned that the insurance reserve has been reduced. And he did not review or evaluate the expenditures to determine whether they were prudently incurred, or whether they had been properly expensed and capitalized. Tr. 8800-8803. He did not know if any of the damage could have been avoided by better tree trimming of maintenance of poles. Cities. OPC. and General Counsel suggest. and the ALJs agree. that this issue can be addressed in the 1998 rate filing when all parties will have the opportunity to evaluate the reasonableness of the changes to the insurance reserve fund. 194 (Emphasis added).

· The above noted items, along with other items set forth in Docket No. 18249, clearly establish that the Company did not perform adequately or prudently and incurred excessive costs associated with the January 1997 ice storm. Therefore, I recommend that

*143 13 Q. HOW SHOULD THE DEDUCTIBLE WORK AS IT RELATES TO THE INSURANCE RESERVE? 14 15 A. If the Company incurred $49,999 of expense associated with the storm, it would absorb

the entire amount as O&M expenditures. However, if the Company captures one additional dollar of expense, then it converts the process to insurance reserve treatment and includes all expenditures associated with such storm in the insurance reserve, rather than only those amounts in excess of the first $50,000. Regulation must provide reasonable and appropriate incentives in order to minimize costs. The failure to recognize a deductible only encourages the occurrence of costs and provides no incentive to act prudently and in the best interest of customers. IS THERE ANY REASON TO TREAT THE FIRST $50,000 OF STORM COSTS

Q.

INCURRED AS INSURANCE RESERVE COSTS?

26 A. No. Failure to treat the first $50,000 of O&M expense related storm expenditures as a 27 deductible insurance practice is inappropriate and must be denied.

109 1 Q.

WHAT IS THE IMPACT OF TIDS RECOMMENDATION?

2 A. The Company's insurance reserve reflects 155 different storms smce Docket No. 16705. ^[195] Therefore, after removal of the ice storm previously discussed, I recommend a 3 4 reduction to the insurance reserve in the amount of $7,700,000, or 154 times $50,000 per 5 storm. 6 7 Q.

PLEASE ADDRESS THE THIRD AREA OF ADJUSTMENT ASSOCIATED

8 WITH MISCELLANOUS INAPPROPRIATE CHARGES. 9 A. As set forth in the table below, the Company has included numerous charges in its storm 10 reserve that do not comply with the Commission's rule. One of the Commission's rules 11 requires charges only for "property and liability losses which occur, and which could not

have been reasonable anticipated and included in operating and maintenance expense." ^[196] 12 *144 Amount ^{[1] [1]} Description

Y

Incentive Compensation $1,002,104 Non-Productive Loading $1,586,480 Fire & Property Insurance $3,555,179 Computer Hardware Acquisitions $487,727 Safety Training Loader $722,796 $7,354,286 Total

13 Items such as incentive compensation are not appropriate. Incentive compensation, to the 14 extent that is allowed in base rates in the first place, will not vary depending on whether 15 an employee's time is expended performing normal services or storm reserve related 16 activity. Thus, such charges easily can be anticipated and reflected in O&M expense. 17 18 Q. IS THE SAME SITUATION TRUE FOR NON-PRODUCTIVE AND SAFETY 19 TRAINING LOADERS AS IS THE CASE FOR INCENTIVE COMPENSATION? 20 A. Yes. The same is true for non-productive loaders and safety training loaders reflected in 21 the reserve. 22

*145 reasonably anticipated and includable in operations and maintenance expenses as noted in the Commission's substantive rules. Indeed, beginning in December of 2007 the Company no longer charged fire and property insurance premiums to its insurance reserve. 199

Q. WHAT DO YOU RECOMMEND REGARDING THE COMPANY'S PRACTICE?

A. I recommend that the $3,555,179 of fire and property insurance premium charges be

removed from the claimed insurance reserve deficit.

Q.

PLEASE DISCUSS YOUR NEXT ADJUSTMENT TO THE INSURANCE RESERVE BALANCE ASSOCIATED WITH THE COMP ANY'S PROPOSED SITUS ADJUSTMENT. As part of the Company's presentation of its current storm reserve deficiency, it identifies

A. a reapportionment of jurisdictional reserve balances due to an analysis during the

I

Jurisdictional Separation Plan split. ^[200] As part of this analysis, the Company attempted to ' *146 Commission upon consideration of the facts and circumstances that necessitate such a change. " ^[202] The Commission further stated that without "detailed analysis and findings of fact, the Commission finds it inappropriate to change Entergy's transmission cost allocation methodology as part of this case." ^[203] In other words, the Company must make a strong showing that its policy changes are appropriate before the Commission will permit a shifting of cost previously charged to Louisiana to be reassigned to Texas customers.

Q. HAS THE COMPANY PRESENTED A FULL AND COMPLETE ANALYSIS OF

ALL JURISDICTIONAL SEPARATION ISSUES IN THIS PROCEEDING?

No. Indeed, prior to allowing a change in the historical allocation of costs between A. ... jurisdictions for the storm reserve, it is incumbent upon the Company to present and justify that all historical jurisdictional charges are appropriately reflected in the Jurisdictional Separation Plan. Failure to do so could and undoubtedly has resulted in Texas retail customers already paying more than their fair share in comparison to Louisiana ratepayers. Therefore, I recommend that the historical allocation of costs ^[201] Response to Rose City 17-26. ^[202] Docket No. 34800 Order on Remand page 10. ^[203] Id.

112 1 between Texas and Louisiana reflected in the storm reserve be retained. This 2 recommendation reverses the Company's proposed reassignment of costs. 3 4 Q.

PLEASE DISCUSS YOUR NEXT ADJUSTMENT TO THE INSURANCE

RESERVE DEFICIT BALANCE. 5 6 A. In association with the securitization process relating to Hurricanes Rita and Katrina, the 7 Company has received insurance proceeds or has revised its insurance estimates

subsequent to the analysis reflected in Adjustment 15 to the Company's filing. ^[204] The 8 ·. 9 Company states there have been two additional changes that impact the insurance related 10 amount reflected in the Company's filing. First, the actual proceeds for Hurricane Katrina 11 received in December 2009 exceeded the estimated proceeds by $7 ,290. Second, the 12 Company revised the estimated proceeds for Hurricane Rita that exceeded the previous

estimate by $1,511,688. 205 Therefore, the combined total of these two insurance proceed 13 *147 related adjustments total $1,518,978 and should be recognized in this case. Q. PLEASE DISCUSS YOUR LAST ADJUSTMENT TO THE INSURANCE

RESERVE DEFICIT BALANCE.

A. I recommend reversal of Company proposed Adjustment 15. This proposed adjustment attempts to remove from the insurance reserve the unrecovered hurricane insurance proceeds, insurance proceeds in excess of insurance proceeds included in the securitization process and carrying costs. 206 ETI proposes to carve $25 million out of the insurance reserve and establish a separate regulatory component for which it also proposes a 5-year amortization. There is no valid basis for this proposed separate and unique treatment. Therefore, ETI's proposed Adjustment 15, Hurricane Securitization, should be eliminated by returning the $25 million amount to the insurance reserve. This recommendation does not impact rate base, but does reduce the net annual amortization by $3,791,732 due to the differing amortization periods (5 years for Adjustment 15 versus 20 years for storm insurance reserve). *148 Target Reserve

13 3. 14 15 Q. WHAT TARGET RESERVE DOES THE COMPANY REQUEST IN THIS PROCEEDING? 16 17 A.

The Company proposes to increase the current $15,572,000 target storm reserve to $19,304,000. This represents an increase of$3,732,000 or 24% above the current target. 18 19 20 Q. IS THE PROPOSED TARGET SIGNIFICANTLY DIFFERENT FROM THE 21 TARGET LEVEL PROPOSED IN DOCKET NO. 34800? Yes. In Docket No. 34800, Mr. Wilson proposed a $37,110,000 total target amount to the 22 A.

reserve. 207 While, the Company's proposed target level in this proceeding is noticeably 23 24 less than what was proposed approximately 2 years earlier, it is still excessive. 25 26 Q. HOW DID THE COMP ANY DEVELOP ITS PROPOSED TARGET IN THIS 27 PROCEEDING? 28 A. Mr. Wilson ran a Monte Carlo simulation on Company loss history. Mr. Wilson performed 5,000 iterations of simulated experience. Based on this simulation, Mr. Wilson 29

*149 13 14 Q. DID MR. WILSON INVESTIGATE ANY OF THE msTORICAL LOSS DATA REFLECTED IN THE MONTE CARLO SIMULATION? 15

No. Therefore, Mr. Wilson cannot attest to the validity of his database as being

16 A.

reasonable and necessary for ratemaking purposes. As previously discussed, the historical 17 18 analysis includes charges that are inappropriate for ratemaking purposes and thus, overstates the target level even if it were to be appropriately based on a Monte Carlo 19 20 simulation. 21 22 Q. DO THE AMOUNTS REFLECTED IN MR. WILSON'S MONTE CARLO 23 SIMULATION ALSO INCLUDE HURRICANE RELATED COSTS? Yes. While the Company has excluded the majority of hurricane related costs, it has still 24 A. 25 included over $40 million of hurricane related costs that were not securitized in its

analysis. 211 26 *150 failing to recognize any other factors that would offset costs results in a skewed database 13 14 that produces artificially excessive cost estimates. 15

16 Q.

WHAT DO YOU RECOMMEND REGARDING THE TARGET STORM RESERVE LEVEL? 17 18 A I recommend retaining the existing target reserve level. The existing target better

represents the historical data after adjustment for identifiable excesses reflected in the losses (e.g., the 1997 ice stonn). Further, retention of existing target level also recognizes that other factors (e.g., a more storm hardened system, computerized mapping systems, etc.) other than inflation have changed from historical time periods that should result in lower stonn losses even if the same event were to transpire in the future.

Q.

WHAT IS THE IMPACT OF YOUR RECOMMENDATION? A. My recommendation results in a $2, 732,000 reduction in the target level reserve. When

this amount is amortized over the same 20-year period proposed by Mr. Wilson, it reduces the Company's storm insurance related revenue requirement by $186,600.

116 1 4. Annual Expected Losses 2 3 Q.

WHAT DOES THE COMPANY REQUEST FOR ITS EXPECTED ANNUAL

4 STORM LOSSES? S A.

The Company proposes to accrue $5,270,000 annually in the self-insurance reserve to

cover expected losses for stonns each year. 212 This amount reflects Mr. Wilson's

6 7 expectation for annual storm losses, except for those storms over $100 million adjusted to

reflect cummt loss levels. 213 8 9 Q. WHAT LEVEL OF ANNUAL EXPECTED STORM LOSSES DID MR. WILSON 10 PROPOSE IN DOCKET NO. 34800? Mr. Wilson proposed an annual accrual of $13,840,000 for expected annual storm 11 A.

*151 losses. 214 12 13 14 Q. HOW DID MR. WILSON DETERMINE HIS CURRENT $5.27 MILLION ANNUAL STORM LOSS PROPOSAL? 15 Mr. Wilson again relied on the previously noted Monte Carlo simulation of the 16 A.

Company's loss history. 215 17 18 HOW DOES MR. WILSON'S CURRENT PROPOSAL COMPARE TO WHAT 19 Q. 20 THE COMMISSION HAS PREVIOUSLY ACCEPTED OR ADOPTED FOR 21 ANNUAL STORM LOSS LEVELS? 22 A. In Docket No. 16705, the Commission adopted a $1,651,320 annual storm loss level. 23 This amount was in place until 2009 when, based on the settlement adopted by the 24 Commission in Docket No. 34800, the annual amount was raised to $3,651,320 annually. 25 Thus, the parties and the Commission believed that a $3.65 million annual storm loss 26 level was reasonable and acceptable as recently as 1 year before the Company filed its 27 current case.

*152 13 Q.

HAS THE COMP

ANY PROVIDED ANY VALID BASIS ON WIDCH TO ADOPT 14 MR. WILSON'S FLAWED MONTE CARLO SIMULATION? No. 15 A. 16

17 Q.

HAS THE COMMISSION RECOGNIZED THE VALIDITY OF RELYING ON 18 msTORICAL AVERAGES AS A REASONABLE APPROACH TO ESTABLISIDNG EXPECTED ANNUAL STORM WSSES? 19 Yes. In Docket No. 35717, an Oncor Delivery case, the Commission accepted an annual 20 A.

storm. loss expectation based in part on a 10-year average of storm cost values. 216 21 22 IS RELIANCE ON A 10-YEAR msTORICAL AVERAGE REASONABLE IN 23 Q. 24 TIDS CASE? No. Given the significant spike of hurricane activity during the last 5 years, reliance on 25 A. too short of a historical average skews the reasonably expected results associated with 26 27 long-term weather conditions. Indeed, just the 2007 value, which includes approximately $25 million of costs associated with Hurricane Humberto, noticeably skews any average 28 29 that relies on too short of a timeframe to an excessive level for purposes of future 30 projections. The 2007 level associated with Hurricane Humberto is more than 8QG/o

*153 the category 1 Hurricane Humberto, indicates that the current existing $3.651 million annual storm loss accrual would be both reasonable and adequate level for annual storm loss accruals. The reasonableness of the existing annual stonn loss level is especially true taking into considerations that the historical data still contains inappropriate storm loss charges for ratemaking purposes. Indeed, both the IO-year and 20-year average of the trended annual storm loss levels, excluding Hurricane Humberto and the 1997 ice storm costs, each yield approximately the existing $3.651 million annual storm loss expected cost approved by the Commission and agreed to by all parties in Docket No. 34800. 217

Q. IS THERE ANOTHER CONSIDERATION THAT MUST BE RECOGNIZED IN ESTABLISHING THE ANNUAL STORM LOSS VALUE?

24 A. Yes. The way the process works is that the annual accrual remains constant until the next 25 rate proceeding. Therefore, the stonn loss reserve was only increased by the $1.651 26 million annual accrual adopted in Docket No. 16705. However, the collection of that 27 amount through base rates is predominantly based on energy charges. Given that there has been growth on the system since 1996, the Company's actually collected through 28 29 base rates much more than the $1.651 million annual accrual. However, customers have not received the benefit of the annual additional amount that the Company has recovered 30 *154 12 Q. WHAT IS THE CURRENT STORM RESERVE THRESHOLD? Any storm-related property loss of at least $50,000 is accounted for in the storm 13 A.

reserve. 218 14 15 16 Q. WHAT IS THE BASIS FOR THE 550,000 MINIMUM THRESHOLD LEVEL? Other than having been approved prior to Docket No. 16705, the Company could not 17 A.

provide any narrative explanation on how the $50,000 level was detennined.2 19 18 19 20 Q. HOW OFfEN HAS THE COMPANY REVIEWED THE $50,000 THRESHOLD 21 FOR REASONABLENESS? 22 A. The Company could not identify a single instance in which it has reviewed the $50,000

minimum threshold for reasonableness. 220 23 *155 intended to allow for storms, "which could not have been reasonably anticipated.',m 12 13 Moreover, the threshold only encourages the Company to accumulate as many charges as 14 possible associated with, or around, a stonn in order to reach the low $50,000 threshold. 15 By reaching such threshold and attempting to employ stonn reserve treatment, the 16 Company can inappropriately manipulate its annual earnings. 17 18 Q. DOES THE MINIMUM SS0,000 THRESHOLD COMPORT WITH THE 19 COMMISSION RULE AS IT APPLIES TO THE COMPARISON TO COMMERCIAL INSURANCE? 20 21 A. No. Indeed, during Mr. Wilson's deposition, he stated that the "deductibles are extremely 22 high" when discussing how insurance companies would set the deductible for the same

service. ^[224] Mr. Wilson's statement was made with knowledge of the $50,000 lower 23 24 threshold for the Company's insurance stonn reserve. Therefore, Mr. Wilson recognizes 25 that insurance compWlies would set a deductible level far in excess of the current $50,000 26 level employed by the Company.

*156 $500,000 per stonn and treating the threshold as a deductible. This level complies with the Commission's rule as it relates to stonns that could not have been reasonably anticipated and is equivalent to what the Commission recently adopted when this issue was contested in Docket No. 35717. This level will further eliminate any unreasonable efforts by the Company to aggregate charges so as to meet the low threshold currently in place and thus remove any incentive for manipulating reasonably predictable O&M expense.

Q. WHAT

IS THE COMBINED IMPACT OF YOUR VARIOUS

RECOMMENDATIONS?

My various recommendations would result in a $3.9 million reduction to the Company's 23 A. 24 expense request for storm damage reserve and a $45.868 million reduction to rate base. *157 12 25.231(c)(2)(BXiii)(IV). 13 14 Q. WHAT HAS THE COMPANY PROPOSED FOR CWC? The Company has proposed a negative $1,979,613 of CWC.n 7 However, the Company 15 A.

has also admitted to two errors relating to state and local franchise fees. 228 The coJTeCtion 16 for those two errors yields a negative $4,869,630 ewe requirement. 17 18 19 Q. WHAT LEVEL OF CASH WORKING CAPITAL DID THE COMMISSION FIND 20 APPROPRIATE FOR THE COMPANY IN ITS LAST FULLY LITIGATED 21 RATE CASE?

ln Docket No. 16705, the Commission ordered a negative $36,016,000 ewe compared

22 A.

to the Company's request for a negative $8,053,000 CWC in that casen 9 In other words, 23 24 the Commission found errors and made adjustments that more than quadrupled the

negative level of ewe requested by the Company. My testimony in that case, upon 25 which the Commission relied in part, also addressed various errors and inappropriate 26 27 positions taken by the Company.

*158 a longer period of time necessary to read a meter and issue a bill than in the past This attempt to rely on a longer period of time signifies that the Company believes it has become less efficient. The regulatory principle that customers should not shoulder the burden of the Company's inefficiencies must be recognized in the lead-lag study. Relying on a meter-to-billing period previously achieved by the Company results in $4,973, 701 more negative ewe.

• BiUing-To-Payment Revenue Lag. The Company relies upon an inappropriate methodology to estimate the time period between when it bills a customer and when a customer pays their bill. Moreover, Company's estimation process reflects the unusual affect of the worldwide financial meltdown that began in the last quarter of 2008. In addition, the Company proposes a 60-day lag for its MSS- 4 affiliate transaction. My recommended methodology relies on a previously accepted approach, with a modification that will eliminate a concern raised by the Commission in Docket No. 16705, and removal of the MSS-4 affiliate transaction results in $26.2 million more negative ewe.

• Customer Float Revenue Lag. The Company proposed a customer float revenue lag of 0.95 days for its retail revenues based on an estimation it believes to be reasonable. The Company's estimation is based on customer count rather than revenues. When revenues are used for the calculation, the float days decline to 0.49 days. The adjustment to the Company's proposed customer float results in $1.6 million more negative ewe.

• Payroll Expense Lead. The Company's proposed lead-lag study does not conform to Commission precedent in Docket No. 16705 as it relates to the service period associated with vacation pay. The Company's attempt to ignore the Commission's decision in Docket No. 16705 stems from its illogical and inappropriate attempt to inconsistently measure the service period for expenses as

124 1 a period when the expense is recorded rather than when the product or service is 2 provided. In addition, the Company also failed to properly recognize the deferred 3 compensation aspect associated with incentive compensation. Reversal of the 4 Company's attempt to not follow the Commission's previous order relating to 5 vacation pay and proper treatment of incentive pay results in $6.3 million more

negative ewe.

6

7 • FAS 106 Expense Lead. 8 In Docket No. 16705, the Commission adopted a 312.55 day expense lead for FAS 106 expenses. The Company again ignores that 9 10 decision by excluding the expense. This is another instance where the Company 11 attempts to employ an illogical and inconsistent approach in order to artificially 12 increase revenue requirements. Complying with Commission precedent on this

issue results in $2.2 million more negative ewe.

13

14 15 • Entergy Services, Inc. Expense Lead. The Company has proposed 38.04 lead 16 days for this category of CWC. The Company bases its lead day proposal on its

*159 operating agreement with Entergy Service, Inc. That agreement permits payment no later than the 25th of the following month. The major problem with the Company's analysis is its failure to recognize that a substantial component of the amount at issue is associated with incentive compensation. Proper recognition of the extended lead days associated with incentive compensation results in $5.6 million of more negative ewe.

• Other O&M Expense Leads. As was the case in prior dockets, the Company has made errors in its stratified sample of invoices used to determine the appropriate expense leads for other O&M. Correction of certain problems in the Company's current stratified sample analysis increases the expense lead days by 15.52 days resulting in $3.6 million of more negative ewe.

Due to the interactive nature between revenue lags and expense leads, the combined

impact of the above various adjustments is not simply the addition of each individual

r

component. Rather, the combined impact is $45.7 million, or $43.7 million more

negative CWC as set forth on Schedule (JP-4).

2. General Q. WHAT ISALEAD-LAGSTUDY? A. A lead-lag study is an attempt to measure the value of the difference between the time the

Company provides services to its customers and the time it receives payment for such services, compared to the time the Company receives a product or service and the time it

125 1 pays for such product or service. As part of the lead-lag study, an attempt is made to measure the revenue lag and compare it to an expense lead. 230 2 3 WHAT ARE THE COMPONENTS OF THE REVENUE LAG? 4 Q. 5 A. Within the revenue lag component of a lead-lag study there are four components: the 6 service period, the billing lag, the collection lag, and the financial or customer lag. The 7 service period normally represents the mid-point of the month in which service is 8 provided. The billing lag represents the time period between the date a meter reading is 9 taken and a bill is issued to the customer. The collection lag is the period between the I 0 time the Company issues a bill to the customer and the date the customer pays the *160 11 Company. Finally, in instances where the Company receives payment in a form other 12 than cash or electronically, it is considered a :financial lag until funds become available. 13 14 Q.

WHAT ARE THE COMPONENTS OF THE EXPENSE LEAD?

Normally for an electric company, the largest single component of expense leads is its 15 A. cost of energy, whether it is through self generation (e.g., coal, oil, gas, or nuclear) or through purchase power costs. Other components are labor, other O&M, property taxes, etc. The Company has identified many categories as set forth on Schedule E.

Q. IS THERE A MAJOR ISSUE REFLECTED IN THE COMP ANY'S CONCEPT OF

A LEAD-LAG STUDY THAT IS CONTRARY TO COMMISSION PRECEDENT?

Yes. Company witness Mr. Gallagher states that "a central issue in the measurement of A. both revenue and expense payment lags is a consistent definition of the Service Period - i.e., the date the utility provides services to its customers for which it incurs costs and accrues revenues and expenses. 231 (Emphasis added). Unfortunately, while Mr. Gallagher desires consistency, the Company's practice, with his oversight, is anything but consistent.

I

*161 11 only when the recording of labor, materials or other costs occur. In other words, he 12 would have the Commission believe that the Company has not received a product or 13 service until it accrues or books the expense not when it receives a product or service. 14 This inconsistent logic between revenue and expense service periods must be recognized 15 for what it is, a direct attack on the Commission's prior decisions and a clear indication 16 of the Company's desire to artificially minimize the negative level of CWC that should 17 be reflected in rate base. 18 3. Revenue Lag

A. Meter Reading To Billing

WHAT HAS THE COMPANY PROPOSED FOR ITS METER READING TO

Q. BILLING REVENUE LAG? I A. The Company proposes 3.63 days associated with its Customer Information System ("CIS") related customers and 3.72 days for large power customers. 232 i Q. ARE THESE REASONABLE LEVELS? l A. No. The Company has invested money into electronic meter reading devices and expensive computer systems that incorporate billing systems. One would hope that the l expenditures of large amounts of capital on such equipment and software would result in *162 11 request to increase the number of days so as to permit verification of potential erroneous billings. 234 The adoption of that position was based, in part, on my testimony in those 12 13 proceedings. The guiding principle for the RCT decision was that customers "should not 14 be punished if a utility decides to manage the business process and payment less

efficiently." 235 15 16 17 Q.

IS THE RCT'S GUIDING PRINCIPLE A REASONABLE AND APPROPRIATE

18 STANDARD? Yes. If the Company elects to allow inefficiencies in the billing process that results in 19 A. 20 higher cost to customers, then such costs should be borne by shareholders, not customers. 21 As previously noted, the customers are already paying for equipment and software that 22 provide the capability of performing the billing process in a much more efficient manner. 23 Moreover, this Company has demonstrated that it can and has completed the meter 24 reading-to-billing process in as little as 1.46 days for the equivalent to the CIS customer

class which comprises the majority of customers and revenues. 236 25 *163 10 full rate of return on the higher level of cash working capital due to its own inefficiencies. 11 The continuation of this situation is neither reasonable nor equitable. 12 13 Q. WHAT DO YOU RECOMMEND? I recommend that the Commission follow the lead of the RCT and adopt a principle that 14 A. 15 customers "should not be punished if the utility decides to manage the business process 16 and payment less efficiently." The Company's incentive to operate inefficiently by 17 earning a higher return is neither reasonable nor appropriate. The Company has 1 8 demonstrated that it can issue a CIS bill within 1.46 days after reading meters. The 19 largest gas utility in the state has demonstrated that it can read meters and bill either on 20 the same day or within one day and has its base rate set on a 1-day meter reading to 21 billing period. Customers are paying for investment in meter reading devices, computers, 22 and software that make it possible to perform the meter reading process in a more 23 efficient manner. Customers are entitled to the benefit of the bargain associated with 24 such expenditures. Based on the various items noted above, I conservatively recommend 25 that a 1.46 day meter reading-to-billing lag for CIS related customers be adopted. This is 26 a level that the Company has demonstrated that it can achieve even prior to its investment 27 in the newer meter reading devices, computers, and software.

129 l Q.

WHAT IS THE IMPACT OF YOUR RECOMMENDATION?

My recommendation on a standalone basis would result in a $4,973,701 more negative 2 A. CWC requirement than what the Company proposed. ^[237] 3 B. Billing-To-Payment Revenue Lag 4 5 6 Q.

WHAT BAS THE COMPANY PROPOSED FOR THE REVENUE LAG DAYS

7 ASSOCIATED WITH THE PERIOD BETWEEN ISSUING BILLS AND 8 RECEIVING PAYMENT FROM CUSTOMERS? *164 9 A. The Company has identified 4 separate revenue lag periods for this component of the

lead-lag study. The Company has proposed 22.26 days for its CIS customers, 16.21 days for its large power customers, 60 days for MSS-4 sales, and 20 days for its other affiliated sales. ^[238]

Q. DO YOU TAKE ISSUE WITH ANY OF THE COMP ANY'S PROPOSALS? A. Yes. I take issue with the Company's proposed 21.80 days for its CIS customers which comprise approximately 53% of the entire revenues, and the 60-day lag proposed for MSS-4 affiliate revenues. ^[239]

Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSED 21.80 REVENUE

LAG DAYS FOR ITS CIS CUSTOMERS?

The Company relies on an inconsistent accounts receivable turnover niethod. ^[240] As will

A.

be discussed later, the Company attempts to relate an end of month amount of accounts receivable to daily average revenues.

Q. IS THE COMP ANY'S OVERALL APPROACH TO THE BILLING TO COLLECTION REVENUE LAG DAYS APPROPRIATE?

A. No. While the Company's actual mechanics has problems, the overall process employed I by the Company is inaccurate. The Company relies on an end of month accounts *165 8 longer reflected in accounts receivable at the end of the month. 9

IO

Q. HAS THE COMPANY'S APPROACH RECENTLY BEEN TESTED IN TEXAS?

A. Yes. In RCT Docket No. 9670, Atmos Energy, the state's largest gas company, proposed the same approach. The RCT found that such approach was unacceptable based in part on my testimony. Distortions can occur due to the difference between daily accounts receivable balances compared to a month end accounts receivable balance in a turnover analysis. This problem can result in several revenue lag days of difference in the Company's billing-to-collection lag.

Q. HAS THE COMPANY'S BILLING-TO-COLLECTION LAG CHANGED OVER TIME? A. Yes. While the Company proposes 21.80 days in this proceeding for its CIS customers, it proposed only 19.02 days in Docket No. 30123. ^[241] Moreover, in Docket No. 16705 the Company proposed 21.63 days and in Docket No. 12852 the Company proposed 19.6 days. ^[242] It also proposed 19.67 days in Docket No. 20150 and 22.26 days in Docket No. 34800. ^[243] Therefore, the Company's proposal in this proceeding represents its second

\

highest requested value over the past numerous rate proceedings and is 1.48 days greater

than the level in place during Docket No. 12852 and 1.41 days greater than the 19.67 billing-to-payment revenue lag in Docket No. 20150.

*166 Q. IS THERE AN ADDITIONAL PROBLEM WITH RELYING ON THE ACCOUNTS RECEIVABLE DATA EMPLOYED BY THE COMPANY?

A. Yes. The test year data includes the period during which this country, if not the world, experienced a financial meltdown and was on the brink of financial collapse. Credit dried up for both individuals and companies. Reliance on this period, August 2008 and for an extended period thereafter, unrealistically skews the revenue lag upward. Therefore, even if the Company's proposed approach were relied on, which it should not be, it is excessively high due to the period contained in the analysis.

Q. CAN YOU PROVIDE AN EXAMPLE OF THE DISTORTION CAUSED BY RELYING ON DATA CORRESPONDING TO THE PERIOD OF ECONOMIC TURMOIL?

A. Yes. A proxy for the impact can be seen from the month end accounts receivable reports for October 2008 and 2009. The October 2008 report identified $1,353,134 of arrears for the 90-day category, while the same value for October 2009 was only $200,111. The 90 days in arrears level of accounts receivable during the thick of the financial meltdown was almost 7 times the level one year later. 245 There were similar situations in other arrears categories.

1

J

*167 adopted in Docket No. 16705. In Docket No. 16705, the Company provided aging of accounts receivable information. ^[246] I recommended an adjustment in that proceeding relying on that information, with one assumption not adopted by the Commission. That assumption was that for those customers under the current pay category, I assumed a conservative 14-day period while the Commission rules allow up to 16 days. 247 The examiners denied this approach since they could "find no reason to justify changing the Commission-required 16-day paid schedule." ^[248] However, the examiners did say they questioned "whether the disconnects really tipped the balance to 16." 249 While I still believe that the 14-day assumption was conservative given that all customers who are current do not pay on the very last day possible, I base my recommendation in this case on adopting the full 16-day payment period allotted by the Commission. In other words, I modified the values set forth on Schedule (JP-17) page 1 of2 in Docket No. 16705 and increased the revenue lag days for the current balances from 14 to 16 days. Increasing the payment period assumption to the absolute maximum permitted by the Commission rules would increase my previously proposed 18.66 revenue lag days to 20.38 days (an additional 1.72 days to reflect 2 additional days time for 85.97 % of customers that pay currently).

*168 Moreover, the Company's proposal is approximately 2.5 days greater than what it has proposed in several prior proceedings. In comparison, my proposed 20.38 days is less than half the difference between what the Company has previously proposed and what it currently proposes and is based on real Company data associated with aging of accounts receivable information utilizing the most conservative assumption for current billings.

Q. DO YOU BELIEVE YOUR ESTIMATE IS TOO CONSERVATIVE? Yes I do. However, given the examiners concerns in Docket No. 16705 and the current A.

situation that the Company has placed both the interveners and Commission in, I find that this conservative approach should cure any concern the Commission previously had in Docket No. 16705 on this issue. Moreover, to the extent the Commission was so inclined and elects to adopt my previous position based on an average 14-day payment period versus the full 16 days permitted under the rule, then the revenue lead would need to be reduced by an additional 1.72 days, or $3,933,198.

Q. WHAT IS THE IMPACT OF YOU RECOMMENDATION? A. My recommendation of a 20.38 bill-to-payment revenue lag for the CIS class results in a

$3,243,718 reduction to rate base (1.42 days x $4,324,957 x 52.8732%). Q. WHAT IS THE ISSUE WITH THE COMPANY'S PROPOSED 60-DAY BILLING

TO PAYMENT PERIOD FOR MSS-4 SALES?

A. Cities' witness Mr. Garrett recommends the removal of the EGSL Sabine and Lewis Creek MSS-4 sales transactions from the Texas retail cost of service. Therefore, I have I removed this component from the revenue lag.

I 134 I i 1 Q.

WHAT IS THE IMPACT OF YOUR RECOMMENDATION?

My recommendation results in a $14.4 million reduction to CWC requirements. 250

2 A. c. 3 Customer Floa t I 4

5 Q.

WHAT HAS THE COMPANY REQUESTED FOR THE REVENUE LAG DAYS

ASSOCIATED WITH THE CUSTOMER FLOAT CATEGORY?

*169 The Company has proposed a lag of0.95 days for the CIS and Large Power categories. 251 A.

Q.

WHAT DOES THIS AMOUNT REPRESENT? A. The Company states this amount represents the check float corresponding to the period

that funds from payment by customers are not available to the Company because checks for payments have not cleared from the customers accounts to the Company's account. 252

Q.

WHAT IS THE COMPANY'S BASIS FOR THE 0.95 DAY REQUEST? A. Mr. Gallagher states that "it ap_pears that after taking into account immediate cash

available from electronic funds transfer" that a 0.95 weighted lag days for retail sales is appropriate. 253 (Emphasis added).

Q.

HAS THE COMP ANY JUSTIFIED ITS REQUESTED CUSTOMER FLOAT? No. First, the Company's proposal is based on customer count and not dollars. ^[254] A. Q. IS IT APPROPRIATE TO RELY ON A CUSTOMER COUNT RATHER THAN

ON THE CORRESPONDING REVENUES?

No. Indeed, the revenue float is quite different from what Mr. Gallagher proposes. The A. Company admits that at least 51 % of its revenues were received in the form of cash, wire *170 6 Company's request is based on the wrong factor (customer count rather than revenues).

I

7 Therefore, I recommend a 0.49-day check float lag for the CIS and Large Power classes. 8 9 Q.

WHAT IS THE IMPACT OF YOUR RECOMMENDATION?

10 A. My recommendation for a 0.49-day customer float reduces rate base by $1,612,822 ((0.95-0.49) x $4,324,957 x 81.06753%). 11 12 13 Q. WHAT IS THE NET IMPACT OF YOUR VARIOUS REVENUE LAG 14 RECOMMENDATIONS? 15 A. The adoptions of the revenue lag adjustments that I have recommended would reduce the 16 Company's overall revenue lag days from 43.17 days to 37.12 days or 6.05 less revenue lag days. A 6.05 reduction in revenue lag days would result in a reduction to rate base of 17 18 $26,169,306 based on the Company's requested level of expenses. 19 4. Expense Leads 20 A. Payroll 21 22 Q. WHAT HAS THE COMPANY PROPOSED FOR EXPENSE LEAD DAYS 23 ASSOCIATED WITH PAYROLL?

The Company proposes 14.55 lead days for the expense lead. ^[256]

24 A.

*171 5 separate component of payroll to account for the lag between when the employee earns 6 vacation time and when the Company pays for it in salary expense" is reasonable. 7 Unfortunately the Company• s calculation in this case fails to recognize the significant

incremental time period associated with vacation pay. 257 8 9 10 Q. DOES THE COMPANY IDENTIFY ANY CHANGED CIRCUMSTANCES THAT 11 WARRANT THE REVERSAL OF THE COMMISSION'S PRECEDENT ON 12 THIS ISSUE? 13 A. No. 14 15 Q. WHAT DID YOU RECOMMEND FOR THE EXPENSE LEAD ASSOCIATED WITH VACATION THAT WAS ADOPTED BY THE COMMISSION IN 16 17 DOCKET NO. 16705? 18 A. As set forth in my testimony in Docket No. 16705 at page 99, I recommended a 210.67 19 day period as the appropriate expense lead days for vacation pay. 20 21 Q. DO YOU STILL BELIEVE THIS LEVEL IS REASONABLE AND 22 APPROPRIATE? 23 A. Due to the change in relationship of vacation pay to total payroll, I am of the opinion the 24 recommended level is conservative. 25 26 Q.

WHAT LEVEL OF VACATION PAY DID THE COMPANY INCUR DURING

27 THE TEST YEAR IN THIS PROCEEDING? The Company incurred $3,842,535 of vacation pay for the test year. 258

28 A.

*172 vacation pay. I then applied the Company proposed 13 day payroll lead period to the remaining payroll. I then added the Company proposed 1.23 lag days for the withholding lag. This results in 35.81 lag days for payroll, or an adjustment of 21.57 days and a reduction to rate base of $2,080,974.

Q. IS THERE A SECOND ISSUE RELATING TO THE PAYROLL EXPENSE LEAD

DAYS?

A. Yes. The second issue deals with incentive compensation. IS THERE A DEFERRED PAYMENT ASSOCIATED WITH INCENTIVE Q.

COMPENSATION?

A. Yes. Just as the situation for vacation pay there is also a deferred payment associated with incentive compensation. Q. WHAT IS THE DEFERRED PERIOD OF TIME ASSOCIATED WITH

PAYMENT OF INCENTIVE COMPENSATION?

The Company paid its annual incentives on March 12, 2009 for calendar 2008 services. ^[261]

A.

Q. WHAT LEVEL OF LEAD DAYS DID THE COMPANY ASSIGN TO INCENTIVE

COMPENSATION? I A. The Company assigned the same 13 day lead it assigned to all other payroll, prior to the impact of withholding items. ^[262] 1 *173 5 recorded. This false opinion must be corrected. 6 7 Q. WHAT IS THE APPROPRIATE NUMBER OF LEAD DAYS FOR INCENTIVE 8 COMPENSATION? 9 A. The appropriate number of lead days for incentive pay is 253.5 days. This level of lead 10 days is based on the average service period of the prior year (365/2) plus 71 days 11 corresponding to January 1 through March 12 of the following year. 12 13 Q. HOW DID YOU CALCULATE THE IMPACT OF TIDS ADJUSTMENT? 14 A. I employed the same methodology that I discussed for vacation payroll. The only 15 difference is that I use $3,688,868 corresponding to the level of incentive

compensation. 263 This process resulted in a 39.43-day increase in the payroll lead days. 16 1 7 This incremental addition is additive to the vacation payroll adjustment. 18 19 Q. WHAT IS THE IMPACT OF TIDS ADJUSTMENT? 20 A. Increasing the overall net payroll lead days from 14.23 days to 25.20 days results in more 21 negative working capital of$2,430,616. B. 22 FAS 106 23 24 Q.

WHAT DOES THE COMPANY PROPOSE FOR LEAD DAYS ASSOCIATED

25 WITH FAS 106 EXPENSES? The Company proposes to exclude this expense from its analyses. ^[264] It should be noted

26 A.

27 that the Company also claims it reflected the impact in the "Other O&M" expense

category. 265 28 *174 5 A. No. The Commission's order in Docket No. 16705 found that FAS 106 expense is a form 6 of deferred compensation and should have a 312.55 day lead assigned to it. 7 8 Q. WHAT ARE FAS 106 EXPENSES? 9 A. FAS 106 expenses represent post retirement benefits other than pensions. In other words,

these amounts represent an employee benefit provided as part of an overall compensation package. FAS 106 costs are deferred compensation.

Q.

DO YOU AGREE WITH THE COMP ANY'S DECISION TO EXCLUDE FAS 106

EXPENSE FROM THE ANALYSIS?

A. Of course not, and neither did the Commission in Docket No. 16705. Mr. Gallagher's presentation in this proceeding is anything but clear or logical. First, he testifies that FAS 106 expenses are not cash expenditures and excluded from his analysis, but then claims that they are treated as "Other O&M" expense. Mr. Gallagher also fails to even reference the fact that FAS 106 expenses are deferred compensation. Thus, just as this Commission has recognized vacation pay as deferred compensation requiring extended number of lead days in comparison to normal payroll days, the same is true for FAS 106 expenses. There is no reason to vacate the Commission's precedent on this matter, especially given the Company's presentation in this proceeding. There are no changed circumstances. There is no underlying support or logic to conclude anything other than cash payments are being made for FAS 106 expenses, that they are a component of ewe, and that they represent deferred compensation.

Q. WHAT DO YOU RECOMMEND? A. I recommend following the Commission's precedent on this matter. In Docket No.

16705 the Commission recognized that such costs are deferred compensation and adopted my recommended 312.55 expense lag days for this category of expense. 266

*175 standalone impact of$2,159,856 of more negative ewe requirement. ^[267] C. Entergy Services Inc. ("ESI") Expense Lead

Q.

WHAT LEVEL OF LEAD DAYS DID THE COMPANY PROPOSE FOR

ENTERGY SERVICE EXPENSES?

A. The Company proposes an expense lead of 39.30 days for expenses associated with Entergy Services, Inc. expense. ^[268]

Q.

WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSED 39.30 LEAD DAYS? A. Mr. Gallagher at page 17 of his direct testimony states that the ETl/ESI Service

Agreement requires payments for ESI services to be made in the month after the expenses are booked. The payment of these costs occur between the 20th and 25th of the month following the provision of service. The actual calculation of the proposed lead days is set forth in the Company's workpapers. ^[269]

Q.

DO YOU AGREE WITH THE COMPANY'S PROPOSAL? A. No. A substantial portion of the Company's charges from Entergy Services, Inc. is

associated with incentive compensation. In fact, during the test year, $9,481,590 of ESI charges were attributable to incentive compensation. 270 As previously noted, incentive compensation represents a form of deferred compensation. Therefore, the incremental

I lead days associated with incentive compensation must be added to the portion of ESI charges that are incentive compensation related. The Company pays its incentive

t

compensation on or about March 15th of the year following the period used to determine

whether incentive compensation has been earned. A March 12th payment yields 253.5 lead days compared to the standard payroll levels reflected in the ESI charges of 13 days.

*176 Q. WHAT IS THE STANDALONE IMPACT OF YOUR RECOMMENDATION? A. Segregation of the ESI related incentive compensation charges from the total ESI

expenses reflected in the ewe analysis, along with the application of a 253.5 lead day period for such incentive compensation results in an incremental negative working capital of $5,564,276. D. Other O&M Expense Lead

Q. WHAT DID THE COMPANY PROPOSE FOR OTHER O&M EXPENSE LEAD

DAYS?

The Company proposed 28.55 days plus 3.84 days for check float, or a total of 32.39 A. days. ^[271] This level is 11.75 shorter than the 44.14 expense lag days Mr. Gallagher supported in Docket No. 34800. 272 In other words, the value in the last case was 36% higher than the current proposed value.

Q. HOW DID THE COMPANY ESTABLISH ITS OTHER O&M LEAD DAY

PROPOSAL?

The Company performed a stratified random sample process of 140 invoices. ^[273]

A.

Q. WHAT IS A STRATIFIED SAMPLE? A stratified sample represents a situation where the variance in a population is recognized A.

by segregating the individual sample items into various stratums or categories that represent different size intervals. In this case the Company recognized that the dollar level of its invoices range from a few dollars to over $240,000. Therefore, it elected to establish different dollar ranges with the highest stratum for invoices over $100,000 and the lowest stratum for invoice amounts less than $250. *177 performing its sample analysis for the other O&M category.

Q.

WHAT TYPE OF ERRORS DOES THE COMPANY'S PROPOSAL REFLECT? A. The Company incorporated prepayments in its sample. Prepayments are already or should

be reflected in rate base in the prepayment category of rate base. The Company also paid invoices early in order to capture a discount. Unfortunately, the discount taken was so small that the Company's actions actually cost customers more than the discount, if not corrected. Customers should not pay for imprudent financial decisions. There are also instances where Mr. Gallagher did not capture the correct service period reflected on the invoice in his sample.

CAN YOU PROVIDE AN EXAMPLE OF EACH TYPE OF ERROR?

Q. A. Yes. For sample item number 8 in the greater than $100,000 stratum, the Company

incurred an invoice with a September 1, 2008 through August 31, 2009 service period. The Company paid that invoice on November 13, 2008 and attempts to claim a negative 99-day lead. ^[274] The payment represents a prepayment and should be excluded from the ewe analyses. An example of the Company's inefficient financial actions can be seen on sample item 9 in the greater than $100,000 stratum. This particular vendor offers a 0.7% discount if the

I invoice is paid within 15 days. The vendor also provides for no discount or penalty if payment is made within 45 days, or 30 more days. The invoice was for $126,190 and by

I paying early the Company received an $883.33 discount. Unfortunately, by paying early the Company now wants customers to incur a loss of 1.45 lead days for the greater than

I

$100,000 stratum. ^[275] Since the greater than $100,000 stratum represents 32.59% of the total stratums, the failure to take full advantage of the 45 day net terms for this single

I

*178 grossed-up overall cost of capital for illustrative purposes yields a $13,188 increase in revenue requirements. In other words, the Company saved customers $883.33 by taking a discount, but wants to charge them $13,188 for its efforts. This is not appropriate. An example of Mr. Gallagher's failure to capture the correct service period can be seen on sample item 13 in the $25,000 to $50,000 stratum. This particular invoice clearly identifies the service period by stating ''for services from 5/31/2008 to 6/27/2008." 276 Unfortunately, Mr. Gallagher relied on a July 2, 2008 date as the service period. 277 WHAT IS THE IMPACT OF THE VARIOUS CORRECTIONS THAT YOU

Q. RECOMMEND TO THE OTHER O&M LEAD DA VS PROPOSED BY MR.

GALLAGHER?

As set forth on Schedule (JP-5), the numerous recommended corrections to the Other

16 A. O&M category increase the Company proposed 28.55 lead days to 44.07 lead days. 17 18 SECTION VII: RIVER BEND DECOMMISSIONING REVENUE REQUIREMENT 19 20 21 Q. WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY? This portion of my testimony addresses the Company's request for decommissioning 22 A. 23 expense revenue requirements associated with River Bend. To the extent the Commission 24 has authority to address this issue, I recommend that the Company's request for a $2.8 25 million decommissioning expense annual revenue requirement be reversed and the 26 existing $0-level of decommissioning expense be retained.

*179 3 REQUIREMENT MATTERS? 4 A. It is my understanding that Cities' witness Mr. Brazell will be addressing this issue as to

whether the Commission has authority to impact a FERC established tariff. However, to the extent that the Commission believes it has authority to address this issue, I recommend the retention of the $0-level of decommissioning expense revenue requirements.

Q. WHAT DOES THE COMPANY REQUEST REGARDING DECOMMISSIONING

REVENUE REQUIREMENTS?

A. Mr. Gillam states that the Company is requesting $2.8 million of annual decommissioning expense. 278 lbis represents a $2.8 million increase from the existing $0-level of expense.

Q. WHAT IS THE COMPANY'S BASIS FOR REQUESTING A $2.8 MILLION REVENUE REQUIREMENT FOR DECOMMISSIONING ACTIVITIES?

18 A. The existing $0-level of decommissioning expense is predicated on Item 9 of the I 19 Settlement Term sheet in Docket No. 34800. Item 9 states that nuclear depreciation and 20 decommissioning amounts reflect the life extension of River Bend. In other words, while the Company has not formally received the 20-year life extension from the NRC for 21 22 River Bend, it did recognize the impact of such extension for ratemaking purposes in its 23 settlement of Docket No. 34800. Now in this case, Mr. Gillam bases his analysis for 24 decommissioning revenue requirements on the initial 40-year life span versus a 60-year

life span for River Bend. 279 25 26 27 Q. IS THE COMPANY'S REVERSAL OF POSITION APPROPRIATE? 28 A. No. The industry as a whole has embarked on and received approval for 20-year license 29 extensions for various nuclear power plants. Indeed, Entergy Corporation has already *180 3 NRC has been given a formal notice that a license extension will be requested for the 4 River Bend station. Thus, the industry, the Company's parent, and the Company all 5 recognize the change in life expectancy for nuclear generating facilities such as River 6 Bend. 7

HOW DID MR. GILLAM DEVELOP ms $2.8 MILLION ESTIMATE? 8 Q. 9 A. Mr. Gillam developed an analysis that reflected estimation of future decommissioning

10 costs, earning rates for different types of external funds, cost escalation rates, 11 management fee levels, as well as other variables. Mr. Gillam estimated these variables

through the year 2034, or approximately 25 years into the future. ^[280] 12 13 14 Q. HOW DOES THE 20-YEAR LIFE EXTENSION AFFECT THE CALCULATION 15 EMPLOYED BY MR. GILLAM? Given that the Company's earnings rate for its trust funds are higher than its estimated 16 A. 17 cost escalation rates yields the straightforward conclusion that a 20-year life extension 18 will reduce the need for additional customer funding of the external trust funds 19 requirements. In other words, estimated earning rates of 4.51 % and higher are greater 20 than the assured 4.25% cost escalation rate. Therefore, the further out into the future the 21 decommissioning process is moved the lesser is the need for further customer 22 contribution to the external funds.

I I '

Q. ARE THERE PROBLEMS WITH

*181 MR. GILLAM'S ANALYSES PRIOR TO

RECOGNITION OF A 20-YEAR LIFE EXTENSION FOR RIVER BEND?

Yes. Mr. Gillam relies on an excessive Texas retail allocation factor (i.e., 42.73% versus A. 42.5%). 281 Mr. Gillam's analysis also understates the starting balance of both external funds by millions of dollars. 282 In addition, Mr. Gillam only addresses future assumed cost escalation for decommissioning activities and fails to address productivity gains or other cost reduction factors.

Q. HAVE YOU ANALYZED THE

IMPACT ON THE EXPECTED DECOMMISSIONING REVENUE REQUIREMENT FUNDS FOR A 20-YEAR LIFE EXTENSION?

A. Yes. Recognition of a 20-year life extension for the River Bend station would eliminate the Company's $2.8 million requested revenue requirements for decommissioning. Recognition of the 20-year life extension in conjunction with the correction noted above would further result in the fact that Texas retail customers have already overpaid their annual decommissioning funding requirements.

Q. HA VE TEXAS CUSTOMERS BEEN TREATED FAIRLY

IN THE

DECOMMISSIONING FUNDING PROCESS?

No. Even though ETI is responsible for approximately 42.5% of River Bend and EGSL is A. responsible for approximately 57.5%, the same situation does not exist for the I

decommissioning fund balance. As of December 31, 2009, Texas retail customers' trust

fund balance was $101 million out of the total $153.5 million balance. 283 Thus, while Texas retail customers have only 42.5% of the plant they have contributed 66% of the total decommissioning fund balance. In other words, Texas retail customers have historically done what was thought to be the "right thing" and contributed to the fund in a responsible, but excessive, manner. *182 HAVE TEXAS RETAIL CUSTOMERS BEEN REWARDED FOR DOING THE "RIGHT TIIlNG"?

A. No. As stated elsewhere in my testimony, the nation as well as the world experienced a financial meltdown in the second half of 2008. Due to the dramatic declines in the equity markets Texas retail customers lost more money than their counterparts in Louisiana. Indeed, Company witness Mr. Caruso stated that ''the jurisdiction that has accumulated the most balance [Texas retail customers] is going to have a bigger share of the gain or loss." 284 Mr. Caruso was right, Texas retail customers have suffered to date much more than their counterparts in Louisiana. First they paid more, then lost more in the worldwide financial meltdown in 2008, and now are being asked to make up for those losses. The Company's decommissioning trust fund treatment of Texas retail customers has not been equitable compared to Louisiana customers.

Q. WHAT DO YOU RECOMMEND? A. I recommend the retention of the current $0-level of decommissioning expense. The 20- year life extension and correction of certain errors would eliminate the Company's request. Additional factors must also be considered. First, even slight increase in the earnings rates or slight decline in the cost escalation factor would further eliminate the need for any current contribution. Indeed, EGSL employs a 2.5% decommissioning cost escalation factor in Louisiana and a 5.7% earnings growth rate. 285 If either of these factors were employed in Texas, the result would be further support for a $0-level of decommissioning accrual. Next, any recognition of gains in productivity would also reduce the need for any further decommissioning contributions. This concept is significant given the decommissioning cost estimate have a built in contingency factor.

I The only necessary contingency factor is time itself. As more time passes, and there is more than 35 years until the 20-year life extension expires, costs, productivity, earnings I

and other factors will be known with greater certainty. Another consideration for totally

eliminating the requested revenue requirements is the fact that if the actual decommissioning process were delayed for a short period, after retirement, it would result

*183 1 in the current fund levels being even more excessive. Therefore, there is no reason to 2 change the current contribution level at this time.

SECTION VIII: RIVER BEND DEPRECIATION RATES

3 4 5 Q. WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY? 6 A. The Company has included a River Bend depreciation analysis in its filing. City witness Mr. Brazell will address whether the Commission has authority to set a depreciation rate 7 8 for the River Bend station. However, to the extent the Commission does set depreciation 9 rate, the rate proposed by the Company must be reduced to reflect the elimination of interim retirements and a 20-year license extension.

IO Q. WHAT DEPRECIATION RA TE DOES THE COMP ANY REQUEST FOR RIVER BEND? A. As set forth in Company witness Mr. Spanos' Exhibit JJS-2, the Company seeks a composite depreciation rate for its nuclear plant investment of 3.6%. This rate is comprised of individual rates for the individual plant accounts and reflects the recognition of interim retirements, an ELG calculation procedure, and a 40-year life span rather than a 60-year life span.

Q. ARE THE RATES PROPOSED BY THE COMPANY APPROPRIATE AND I REASONABLE? A. No. As previously noted under the depreciation section of my testimony, the Commission has historically denied the inclusion of interim retirements. The current rates for River Bend do not reflect the impact of interim retirements. In addition, also discussed in the depreciation section of my testimony, the use of the ELG depreciation procedure is inappropriate. Finally, the life span proposed by the Company is artificially short based on the available facts.

149

RIVER BEND DEPRECIATION RATES

*184 ETI Account Cities 321 2.99% 1.33% 322 3.67% 1.53% 323 4.24% 1.66% 324 3.14% 1.32% 325 5.03% 2.10% Total 3.36% 1.42%

As can be seen in the table above, the 20-year life extension and elimination of interim retirements significantly reduces the necessary depreciation rates and depreciation expense requested by the Company by $26,671,803 for the Texas jurisdiction based on plant as of December 31, 2008.

Q. DOES TillS CONCLUDE YOUR TESTIMONY? Yes. However to the extent I have not addressed an issue, method, procedure, etc., that A.

should not be construed that I am in agreement with the Company's issue, method, procedure, etc.

I 150

NOTES

[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

[3] PUCT’s Appellee’s Brief at 16-17.

[4] See id. at 18. 2

[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

[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

[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

[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

[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

[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

[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

[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

[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

[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

[34] See TIEC’s Appellee’s Brief at 33. 15

[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

[37] State Agencies have not yet appeared or designated a new lead counsel in this appeal. 20

[1] Gulf States Utilities Corporate Plan 1980-1984 item l(c). 6

[2] Title 18 Code of Federal Regulations Part 101.

[4] PUC Docket No. 34800 Final Order FOF 34. s Exhibit JJS-1pages209-252.

*48 [7] 2008 Study at Exhibit JJS-1 page 35. 14 Q. WHAT SPECIFIC ITEM OF INFORMATION HAS THE COMPANY PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE LIFE SP ANS FOR ITS GENERATING UNITS REFLECTING "CONSIDERATION OF THE AGE" OR "USE, SIZE, NATURE OF CONSTRUCTION" OF ITS UNITS? The Company has provided no information that would support its proposal for a life span A. as short as 46 years for Sabine 5. In fact, Sabine Units 1 and 2, which are much smaller and dispatched less than Sabine 5, have already reached ages in excess of 46 years. Thus, judgment in conjunction with consideration of age or physical characteristics of the units should have caused the Company to propose longer life spans than it has. Q. WHAT SPECIFIC ITEM OF INFORMATION HAS THE COMPANY PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE LIFE SPANS FOR ITS GENERATING UNITS REFLECTING "MANAGEMENT OUTLOOK"? The Company has provided no information that would support its proposals. In fact, the 16 A. timing horizon of the Company's Strategic Resource Plan ("SRP") is through 2028. 8 The 17 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 PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE 24 LIFE SP ANS FOR ITS GENERA TING UNITS REFLECTING "TYPICAL LIFE 25 SPANS EXPERIENCED AND USED BY OTHER UTILITIES OF SIMILAR 26 ~ 27 FACILITIES"? I The Company has provided no information. However, through discovery, it was 28 A. 29 determined that Gannett Fleming has supported a range of life spans for gas-fired units I that is so wide that it would allow for a selection of about any value, even ones 30

*49 [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 "judgmental" process claimed by Mr. Spanos. 3 4 5 Q. DOES MR. SPANOS' TESTIMONY PROVIDE SUFFICIENT EXPLANATION 6 AND JUSTIFICATION TO SUPPORT THE COMP ANY'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 such as: • System maintenance good; • Control upgrades; • Monthly vibration program, performance tests; and • Boiler exam and maintenance every year. 9 Q. DO THESE ADDITIONAL STATEMENTS CONTAINED IN MR. SPANOS' SITE VISIT NOTES PROVIDE SUFFICIENT SUPPORT FOR THE COMPANY'S LIFE SPAN PROPOSALS? No. These statements represent the type of statements one would expect relating to a A. dynamic situation requiring decisions whether to retire units or continue to expend funds to permit continued operation. In fact, it is quite clear from these comments and other information in the 2008 Study that the Company has historically decided, and currently is deciding, to make necessary capital expenditures to keep its units in operation long after the claimed initial design life. The Company has faced the decision whether to retire these units or spend funds to keep them in operating condition beyond initial expectations and in each instance has decided that it is economically appropriate and efficient to do what all other utilities have been doing: maximize the life of a capital-intensive asset.

*50 [9] Response to Rose City 1-15 Attachment. 16 There is more support for longer life spans in Mr. Spanos' notes than there is for the artificially short life spans being proposed. Q. DID MR. SP ANOS PROVIDE ANY ADDITIONAL INFORMATION REGARDING ms PROPOSED LIFE SP ANS DURING ms DEPOSITION? Yes. Mr. Spanos stated that the life spans corresponded with the best estimate of the A. likelihood of assets being either taken out of service (i.e. retired), or the date of expected major capital additions in the future made to change the functionality of the asset. 10 He also admits that the proposed retirement in his study does not necessarily relate to when the units would be shut down. 11 These two statements taken together default to a position that the probable retirement dates in Mr. Spanos' study are the unsubstantiated date Mr. Spanos assumes the Company may make major capital additions to change the functionality of the units. Q. IS THERE ANYTHING IN THE USOA THAT DEFINES OR TIES THE SERVICE PERIOD FOR A GENERATING UNIT TO AN ASSUMED DATE WHEN A UTILITY MIGHT MAKE A MAJOR CAPITAL ADDITION THAT CHANGES THE FUNCTIONALITY OF AN ASSET? A. Absolutely not. Q. DID MR. SP ANOS OR THE COMP ANY PROVIDE A SINGLE DOCUMENT THAT DEMONSTRATES THE PROPOSED RETIREMENT DATES ARE THE COMPANY'S BEST ESTIMATE OF WHEN A UNIT WILL RETIRE? I 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

*51 [10] Deposition of Mr. Spanos on April 20, 2010 at TR 39. I II Id. 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? No, Mr. Spanos' concept is a backdoor approach to recognizing interim additions, 5 A. something the PUC and other regulators do not permit. 6 7 8 Q. WHAT ARE INTERIM ADDITIONS? 9 A. Interim additions are theoretical future dollars of investment or capital additions in plant to be added to existing facility of the Company. Such additions are not the dollars of 10 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 PURPOSES? 16 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.

*53 [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 depreciation rates, but is obligated to do so to assure that as near as 2 possible the service value of electric plant is fully recovered during its 3 4 useful life. For all these reasons, we find no basis to approve Commonwealth's depreciation methodology. 14 5 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 spans longer than ETI has for comparable units. 15 A listing of comparable size and age of 17 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 COMPARABLE UNITS 21 Size Year Life Size Year Life ETIUnit (MW) Installed Span SWEPCOUnit <MW) Installed Span Lewis Creek # 1 271 1970 55 Wilks #2 357 1970 65 271 Lewis Creek #2 1971 54 Wilks #3 358 1971 65 Sabine #1 240 1962 63 Wilks #1 175 1964 65 Sabine #2 240 1963 62 Willes #1 175 1964 65 Sabine #3 473 1967 58 Willes #2 357 1970 65 Sabine #4 592 1974 51 KnoxLee#5 344 1974 65 Sabine #5 507 1977 46 KnoxLee#5 344 1974 65

*54 [14] 23 FERC at page 61,469.

[15] PUC Docket No. 37364, Exhibit DAD-I page 25. 20 C. Recommendation Q. DO YOU BELIEVE THE COMP ANY'S PROPOSED RETIREMENT DATES FOR GENERATING UNITS ARE APPROPRIATE FOR DEPRECIATION PURPOSES? A. No. The Company's proposed life span for its gas-fired generating units assumes a 2025 retirement date. The Company's most recent SRP clearly dispels the credibility of that date. Moreover, the Company has not shown why it cannot obtain life spans for its units comparable to what other utilities have already achieved or are now projecting. Finally, there is no credible basis for the Company to propose that the largest two gas fired units, Sabine Units 4 and 5, will only be able to achieve life spans of 51 and 46 years, respectively, while its two smallest and oldest units, Sabine Units 1 and 2, are projected in the 2008 Study to achieve life spans of 63 and 62 years, respective. 16 These life span estimates are extended at least to 67 and 68 years, respectively in the most current SRP. The Company's production life span proposals are neither logical nor credible. IS THERE ANY DOUBT THAT GAS-FIRED STEAM GENERATING UNITS Q. CAN LAST AS LONG AS 65 YEARS OR LONGER? No. First, ETI now recognizes that Sabine Unit 1 will operate for at least that length of A. time. 17 In addition, Mr. Spanos supports life spans for gas-fired units of up to 67 years for Entergy Arkansas, Inc. ("EAi"), ETl's sister utility in Arkansas. 18 Moreover, the U.S. Energy Information Administration ("EIA") maintains a database of operating generating units in service through 2008. That database identifies over 500 natural gas-fired units 26 that had already reached 46 years of age (the short life span proposed for Sabine 5) by the ~ end of2008, with almost 30 of those units exceeding 200 MW in size. 19 27 I

*58 [25] Id., at TR 96.

[26] Exhibit JJS-1, pages 209-254.

[27] Id., at pages 56-80.

[28] OLT reflects the actual retirement pattern exhibited over a given period. 24 Commission were inclined to change its precedent on this matter, "guessed" at or forced results cannot be accepted as a valid basis for the inclusion of the impact of interim retirements. Another consideration relating to Mr. Spanos' proposal in this case is his constant practice of relying on industry data. With this in mind, it is worth noting that Mr. Spanos proposed much longer ASLs for the same accounts in his current El Paso Electric testimony before the Commission, as shown in the table below. COMPARISON OF INTERIM RETIREMENT CURVES Increase to EPE % Account ETI EPE Years 65-R2 35 54% 311 100-Sl.5 55-R2 45% 312 80-82.5 25 314 50-82.5 75-R4 25 50% 315 50-S0.5 65-Sl.5 15 30% 50-Rl.5 60-R3 10 20% 316 Moreover, it must be noted that Mr. Spanos had basically the same level of utility specific OL T data with which to work with in both cases. Therefore, it appears that the difference between the two contemporaneous studies both filed at the same time before this Commission is the depreciation policy in place for ETI. Finally, it is worth noting that the Florida Public Service Commission ("FPSC") this year denied the method of calculating interim retirement employed by Gannett Fleming recognizing many of the problems noted above. 29 I Q. WHAT DO YOU RECOMMEND? I Given that this Commission has consistently denied the recognition and inclusion of A. interim retirements for production-plant deprecation rates in prior proceedings, I I recommend that the Commission precedent on this matter be recognized for ratemaking

*60 [30] Exhibit JJS-1, pages 51 and 52.

[31] Exhibit JJS-1, pages 51 and 52, setting the net salvage percentage to zero {O).

[32] Direct Testimony of Mr. Spanos at page 22. 26 1 In other words, the Company performed what it claims is a common industry practice of 2 performing linear regression analysis on some unidentified data set to arrive at an 3 unidentified regression equation, which can then be applied to the individual megawatt 4 size of the Company's generating units. Once a current cost value has been established 5 under this method, Mr. Spanos then escalated the costs into the future until the proposed 6 retirement date for the Company's various generating units. 7 8 Q. CAN YOU PROVIDE A SPECIFIC EXAMPLE OF WHAT THE COMPANY PROPOSES? 9 Yes. Mr. Spanos claims his regression analysis yields a $40.61 per kW dismantlement 10 A. cost for the Big Cajun coal-fired generating unit. 33 He then applies that value to the 588 11 12 Mw size of the Big Cajun coal unit, which yields an estimated cost of $23,878,680 in 13 2008 dollars. Mr. Spanos then applied ETI's 42.5% ownership share of what he believed 14 was the Entergy ownership share of the Big Cajun unit, in an attempt to establish a $10,148,439 cost applicable to ETI. Mr. Spanos inflated that 2008 cost figure at an 15 16 annual compounded rate of 3 % for 3 5 years into the future, the assumed future retirement 17 date for the Big Cajun unit. The result is an estimated future dismantlement cost of $28,536,311. 34 The future escalation of cost raised the requested cost level by multiplying 18 i the current cost level by a factor of 2.814 (l.03< 35 ». 19 20 21 Q. SETTING ASIDE FOR THE MOMENT THE REGRESSION AND ESCALATION CONCEPTS EMPLOYED BY MR. SPANOS, IS ms CALCULATION 22 23 CORRECT? I No. For Big Cajun and Nelson 6, Mr. Spanos failed to reduce the stated MW size of the 24 A. 25 units for Entergy's ownership share. While Mr. Spanos did apply a 42.5% ownership I share allocation between ETI and Entergy Gulf States Louisiana ("EGSL"), he failed to 26 recognize that these are jointly owned units with other utilities. In particular, Cajun 27 l 28 Electric Power Company, Inc. owns 58% of the Big Cajun unit, while other utilities own

[33] Exhibit JJS-1page189, column (a).

[34] $10,148,439 X l.03

[3] S = $28,536,31). 27 1 for these units even if one were to accept his linear regression and future cost escalation 2 approach. 3 4 Q. IS THE LINEAR REGRESSION ANALYSIS AS PROPOSED BY MR. SP ANOS A 5 COMMON INDUSTRY PRACTICE AS CLAIMED? 6 A. No. In fact, when requested to provide support for such claim, all Mr. Spanos could state was that it "is utilized by many utilities." 35 Clearly, the claim is incorrect. Indeed, no 7 8 other use of the "common" industry approach was found in review of the recent testimonies of Mr. Spanos. 36 9 10 11 Q. WAS MR. SP ANOS REQUESTED TO IDENTIFY OTHER UTILITIES WHERE 12 GANNETT FLEMING HAD EMPLOYED A METHOD OTHER THAN LINEAR 13 REGRESSION ANALYSIS FOR PRODUCTION PLANT NET SALVAGE DURING THE PAST 3 YEARS? 14 15 A. Yes. Surprisingly, Mr. Spanos only identified two examples in response to this request for information. 37 What is surprising about Mr. Spanos' response is that he currently has a Gannett Fleming depreciation study on behalf of El Paso Electric before the Commission in Docket No. 37690. In that depreciation study, Mr. Spanos did not employ a linear regression analysis for production plant net salvage. In other words, two contemporaneous depreciation studies performed on two different utilities both providing service in Texas, both of which have been filed before this Commission, reflect inconsistent application of what Mr. Spanos claims is a "common'' industry practice. DID MR. SPANOS IDENTIFY ms STANDARD FOR PRODUCTION PLANT Q. DISMANTLEMENT COSTS DURING A RECENT DEPOSITION? 26 A. Yes. In the El Paso Electric case noted above, Mr. Spanos stated during his deposition the 27 following regarding his standards for production plant terminal net salvage:

*62 [35] Response to Rose City 12-S(a).

[36] Response to Rose City 1-3.

[37] Response to Rose City 12-5(b). 28 I feel as though you need to incorporate a terminal net salvage component or a -- what's called a decommissioning study to be incorporated into the development. However, if the company has not gone through the practice of getting the estimate on that or does not have any determination of what their plans are at final dismantlement, it's, in my opinion, not proper to build in a terminal net salvage component without some sort of support. The company [El Paso Electric] at this time hadn't had any plans, so we've not included that. But there is going to be a major cost to dismantle these facilities, and that needs to be built into rates for production facilities as a full-service value of that facility. But unless you have a specific plan or at least an idea of what's going to happen, I don't think it is wise to build that into rates. But I think that's something that's going to be a consideration here. 38 (Emphasis added.) In other words, Mr. Spanos has established his standard for production plant terminal net salvage in the El Paso Electric case, which is inconsistent within his proposal in this proceeding. He admits that it is not proper to build in a terminal net salvage component without some sort of support. Neither ETI nor El Paso Electric produced a decommissioning cost estimate and neither have specific plans as to what would transpire I at the time of retirement. Q. CAN MR. SPANOS CLAIM THAT HE DID NOT HAVE THE DATA NECESSARY TO PERFORM THE "COMMON INDUSTRY PRACTICE OF LINEAR REGRESSION ANALYSIS" IN THE EL PASO ELECTRIC CASE THAT HE HAS PROPOSED IN TIDS CASE? No. Mr. Spanos claims that his firm obtained this data in the early 1990s. Thus, Mr. A. Spanos had the information available for his El Paso Electric study and testimony, yet I found it not wise to rely on it there, unlike his decision in this proceeding. 1 I

*63 [38] Deposition of Mr. Spanos on March 25, 2010 in Docket No. 37690 at page 86. 29 SETTING ASIDE MR. SPANOS' FAILURE TO COMPLY WITH ms OWN 1 Q. STANDARD AND ms INCONSISTENT TREATMENT BETWEEN EL PASO 2 3 ELECTRIC AND ETI, ARE THERE MAJOR PROBLEMS WITH THE 4 COMP ANY'S PROPOSED REGRESSION ANALYSIS? 5 A. Yes. The Company's basis for its production net salvage has almost too many problems to enumerate. However, the following are some of the major problems: • No underlying data exists to support the claimed regression data points; • No first-hand knowledge exists of where the data came from; • Assumed future inflation rates are inconsistent with what the Company's rate of return witness is proposing in this case; • Proposing that current customers pay with current dollars for future inflated costs while failing to discount such costs back to a present value level is rm proper; • Reliance on a false premise that the data points in the regression analysis represent actual dismantlement costs of generating units over many years, rather than being associated with dismantlement cost estimates for plants that have not been dismantled is improper; • Mathematical errors exist in the net salvage process; and • Failure to recognize or understand the dramatic underlying differences between assumed values or values within the regression database associated with comparable sized units leads to flawed results in addition to the flawed results generated by the flawed analysis. Q. PLEASE DESCRIBE THE DATABASE RELIED UPON BY MR. SPANOS TO DEVELOP ms REGRESSION ANALYSIS. 27 A. As set forth in the Company's response to Rose City 12-5, Mr. Spanos claims 28 approximately 60 data points associated with demolition costs for coal-fired generating 29 facilities. However, he does not have a single item of information associated with the 30 underlying data points. In other words, he cannot identify the units, stations, year in 31 which the dismantlement supposedly occurred, the process employed, the utility at issue 32 or anything else about the underlying data. Review of the data points indicates a mixture 33 of individual units with stations that are comprised of multiple units. The smallest data

[39] Deposition of Mr. Spanos on April 20, 2010 at TR 117.

[40] Id.

[41] NPSC Docket Nos. 03/1001-03/1002.

[42] Rebuttal Testimony Mr. Spanos, page 16 in NPC Docket Nos. 03-1001/03-1002. 32 facilities by ETI. Most of the decommissioning studies in the late 80s and early 90s reflect a substantial amount of dollars for site restoration. Such costs would be inappropriate if a utility were to reuse the facility, as those costs would be associated with the new installation. Simply put, multiple problems with the Company's production net salvage analysis render it unreliable for any purpose in this proceeding. Q. DOES MR. SPANOS FURTHER EMPLOY AN EXCESSIVE DEPRECIATION CONCEPT IN ms PRODUCTION PLANT NET SALVAGE PROPOSAL? A. Yes. After inconsistently relying on a linear regression analysis for his proposal in this case and obtaining results that lack credibility, Mr. Spanos takes another major inappropriate step. That step is to escalate the results of his regression analysis for net salvage costs into the future until the projected date of retirement. Mr. Spanos relies on a 3% inflation factor, which he claims is representative of the Consumer Price Index ("CPI") over the last 40-50 years. 43 Q. DID MR. SPANOS DISCOUNT THE FUTURE ESCALATED COST BACK TO THE PRESENT PERIOD? A. No. Mr. Spanos believes that the negative net salvage to be reflected in current rates must include the cost to demolish a unit at the time of retirement. 44 In other words, Mr. Spanos proposes to have current customers pay in current dollars for future costs that may have been escalated as many as 3 5 years into the future. Q. IS TIDS APPROPRIATE? I A. No. ~

[43] Deposition of Mr. Spanos on April 20, 2010 at TR 125.

[44] Id., at TR 124. 33 l Q. HA VE OTHER COMMISSIONS DENIED REQUESTS FOR INCLUSION OF 2 FUTURE INFLATION IN THE CALCULATION OF PRODUCTION-PLANT 3 NET SALVAGE? 4 A. Yes. Recently, the Oklahoma Corporation Commission ("OCC") denied the identical request in a Public Service of Oklahoma ("PSO") case. 45 Another example is the NPSC in consolidated Docket Nos. 91-5032 and 91-5055. In that case the NPSC stated the following: Since NPC has no terminal salvage and cost of removal experience for steam and combustion turbine generating units, Mr. Ferguson [the utility witness] relied on demolition studies of other utilities, adjusted for the expected inflation between the study date and date of removal, in determining his recommended rates .... Mr. Pous criticized Mr. Ferguson for applying inflation to the cost of removal or demolition studies without also taking into consideration other factors such as the potential sale of production facilities or increased labor productivity which might impact gross salvage or cost ofremoval .... Mr. Pous' arguments regarding the unreasonableness of Mr. Ferguson's proposed net salvage factors for Steam Production Plant are persuasive. It is apparent that Mr. Ferguson has selected only a limited number of demolition studies and interpreted them in a manner to suwort his position without adequately considering all factors involved. ... (Emphasis added). In another case, the Michigan Public Service Commission ("MPSC") in case No. U9493, a Consumers Power Company case, stated the following regarding the incorporation of future inflation in determining net salvage for production plant: The Commission finds that Consumer's arguments must be rejected for several reasons. First, contrary to Consumer's assertions, it is not clear from the Commission's definitions of salvage value and cost of removal that future inflation must be included in the net salvage used to calculate depreciation rates. In fact, a review of those definitions reveals that they

[45] OCC Cause No. 200800144. 34 Consumer's did not consider future technological changes that might reduce removal costs. For these reasons, the Commission finds that Consumer's proposal is not in the public interest. Future inflation should not be reflected in the terminal net salvage for steam production plant. (Emphasis added). The concept underlying net salvage for depreciation purposes is to estimate a reasonable level of net salvage to include in current rates so that current customers will pay their fair share of any such costs. To assume that inflation is the only factor that impacts future cost of removal is simply wrong. Many areas of construction or demolition that entail potentially large costs are subject to technological changes and process improvements. For example, the demolition or toppling of large smoke stacks rather than taking such structures down brick by brick is one improvement. Thus, Mr. Spanos' focus solely on inflation distorts any credible results obtained from the analysis. Q. IS THERE ANOTHER SIGNIFICANT REASON WHY INFLATION AS PROPOSED BY THE COMPANY IS INAPPROPRIATE? A. Yes. Current customers should pay their current cost in current dollars. Under ETI's proposal, customers would be forced to pay for future costs established at a future dollar level without any discounting back to current dollar levels. This is simply not a logical conclusion and is not an accepted practice in utility ratemaking. For example, when future inflation is taken into account in the establishment of external decommissioning fund payments for nuclear plants, not only is an inflation or escalation rate included in the overall calculation, but an earnings or discount rate is included as well. The earnings or discount rate is included in order to recognize time value of money that occurs between a I dollar being spent or invested today and a dollar spent or invested at some point in the future. ETI's total failure to recognize a discount rate is a fatal flaw in its proposal. ~ Q. 29 WHAT DO YOU RECOMMEND FOR PRODUCTION PLANT NET SALVAGE?

[46] Deposition of Mr. Spanos on March 25, 2010 in PUCT Docket No. 37690 at TR 91.

[47] Several conversations with Mr. John Tompeck, Capital Project Engineer for the Ft. Pierce Utilities Authority.

[48] Several phone conversations with John Tompeck Project Engineer for the King Generation plant demolition plant for the Ft. Pierce Utility Commission, Ft. Pierce, Florida. I 36 I 1 America came, dismantled the boiler and other equipment, and shipped it to Central America for on his sugar cane plantation. 49 Moreover, when investor owned utilities 2 3 demolish power plants, usable items are sold or transferred rather than scrapped. 4 5 Q. ARE YOU AWARE OF OTHER EVIDENCE THAT EQUIPMENT AT 6 DEMOLISHED POWER PLANTS CAN AND HAVE BEEN SOLD RATHER 7 THAN CONSIDERED USABLE ONLY FOR SCRAP VALUE? 8 A. Yes. A presentation was made at a decommissioning conference regarding Florida Power & Light Company's ("FPL") Palatka decommissioning project. One of the slides in that presentation clearly notes under the heading Salvage/Sale that the turbine/generator for Unit 1 at that station was sold.so 1bis fact was confirmed by FPL's decommissioning documents. In spite of an active "after market" for power plant equipment, when it comes to presenting a proposal, Mr. Spanos believes that selling pieces of equipment is unlikely because there are so many requirements as to perfectly matching equipment.st In contrast to this false assumption, he is more than willing to offer negative 15% to 32% values without any underlying support. Q. HOW HA VE THE ECONOMIES OF CHINA AND INDIA IMPACTED DEMOLITION COST ESTIMATES? A. The dramatic expansion of these economies has resulted in substantial upward pressure on scrap metal prices. Prices for scrap copper are now over $3.00 per pound, while in the early 2000s the price was more in the $0.40 price per pound range. Indeed, ETI admits that it obtained $0.5039 per pound for scrap iron in 2008 while it was only able to obtain $0.0621 per pound back in 2003.s 2 Since the demolition of a power plant produces large quantities of copper, steel and other metals, the gross salvage associated with the sale of scrap metal can exceed the cost of demolition.

*71 [49] Web article at http://www.tclp.org/news_details.php?id=l22, and discussions with Traverse City electric department personnel. so Response to AXM 6-93 in PUCT Docket No. 35763.

[51] Deposition of Mr. Spanos on March25, 2010 at TR 89.

[52] Response to Rose City 1-34. 37 1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 2 A. On a standalone basis my recommendation results in an $11. 7 million reduction in annual depreciation expense based on plant as of December 31, 2008. 3 4 5. Mass Property Life 5 A. Introduction 6 Q. WHAT IS THE PURPOSE OF THE LIFE PORTION OF A DEPRECIATION 7 ANALYSIS? 8 A. The purpose of a life analysis is to determine the "average service life" or ASL, the dispersion pattern and remaining life for each account or subaccount. This information is necessary to properly perform the depreciation calculation. A longer ASL results in a longer remaining life and therefore a lower depreciation expense. Alternatively, a shorter ASL will reduce the remaining life and increase depreciation expense. The dispersion pattern is also important, as it is critical in the overall selection process of the best fitting results. The same ASL with different Iowa Survivor Curves also results in different remaining lives, due to the remaining expected pattern of retirements. Q. WHAT ARE THE MAIN TOOLS UTILIZED IN PERFORMING LIFE ANALYSIS? Life analysis is normally performed by actuarial or semi-actuarial analyses. Actuarial 19 A. 20 analyses rely on aged data. In other words, when an item of property is retired, the age at 21 retirement is known. 1bis is the type of analysis performed by insurance companies 22 when developing life tables in order to establish premiums. Semi-actuarial analyses are 23 performed in instances in which the age of retired plant is not known. 24

[53] Impact estimated based on change in ALG remaining life due to ELG calculation by ETI. 41 The combined impact of the various adjustments I recommend results in a standalone impact of an $11,091,546 reduction to annual depreciation expense, based on plant as of December 31, 2008. 54 Q. HOW ARE THE ULTIMATE LIFE-CURVE SELECTIONS MADE? A. From an actuarial standpoint, the best fitting life-curve selections are made by visually matching the OLT to standardized Iowa Survivor Curves. Mathematical curve fitting is flawed when it assigns an equal level of significance to each point in the matching process. Indeed, Mr. Spanos' admits that even though he does perform mathematical curve fitting as a part of his analysis, he does not "view that to be the proper way to do life analysis." 55 Q. IN THE VISUAL MATCH PROCESS, ARE ALL POINTS OF COMPARISON EQUAL? A. No. Many of the points of comparison for an OL T may reflect dollar levels of exposures that differ by a factor of 10,000 or more. Indeed, Mr. Spanos also notes, but does not adequately implement in his analysis, that a "significant portion" of the curve exists as it relates to the curve matching process. 56 In other words, the "head" or top of the curve and possibly middle portions of the curve are more significant in the curve fitting process than is the "tail" of the curve. Q. IN THE CURVE FITTING PROCESS, IS IT MORE IMPORTANT TO MATCH THE POINTS ON THE OLT THAT REFLECT LARGER DOLLAR LEVELS OF EXPOSURES THAN THOSE POINTS WHERE THE DOLLAR LEVEL IS MUCH LOWER?

[57] Exhibit JJS-1 page 52.

[58] Exhibit JJS-1 page 36. 43 1 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? No. The Company's proposed 65-year ASL is artificially short. Land rights for 2 A. transmission lines are difficult to obtain. The "not in my backyard" (''NIMB") syndrome is stronger than ever as it relates to new transmission right-of-way locations. Therefore, utilities will continue to rely on existing transmission land rights into the future absent unusual circumstances. In addition, all transmission right-of-ways remain in place until the utility releases its right to the land. 59 Thus, the land rights can easily be in place for multiple life cycles of the equipment that rests upon such land rights. Indeed, the Company's proposed ASL for this account represents a period shorter than a single maximum life cycle for the equipment that resides upon the land right. This is illogical on its face. In other words, the Company proposes a 53-R2.5 life-curve combination for Account 356 - Transmission Overhead Conductors & Devices. The maximum life, a complete life cycle, for an investment with this life-curve combination is in excess of 95 years. Yet the Company proposes an ASL for easements of only 65 years. Q. HOW MANY EASEMENTS HAS THE COMPANY RETIRED IN ITS RECORDED IDSTORY? 18 A. None. The Company does not report a single retirement during the 50 years of retirement activity reflected in its study. 60 19 20 21 Q. WHAT DO YOU RECOMMEND? I recommend a 95-R4 life-curve combination. This ASL is conservative as it corresponds 22 A. 23 approximately to only one maximum life cycle for overhead conductors and devices. 24 Obviously, additional investment has and will continue to be placed into service on the

[59] Response to Rose City 13-5.

[60] Exhibit JJS-1 pages 86 and 87. 44 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? A. My recommendation of a 95-year ASL on a standalone basis results in a $183,605 reduction in depreciation expense based on plant in service as of December 31, 2008. Account 353 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 353 - TRANSMISSION STATION EQUIPMENT? The Company proposes a 45-R2.5 life-curve combination. 61 A. Q. WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL? A. This is an account where Mr. Spanos did not rely to any extent on the statistical analysis he performed on the historical data. 62 This is an account where Mr. Spanos relied on his standard statement of judgment, nature of the plant, previous estimates, and similar lives for other electric companies. 63 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? A. No. The Company's proposal understates the realistic life expectancy for this account; therefore, I recommend a 52-R2.5 life-curve combination as a better representation of the life expectancy for this investment. Q. WHAT IS THE BASIS FOR YOUR RECOMMENDATION? First, the historical actuarial analysis does provide some useful information. While Mr. A.

[61] Exhibit JJS-1 page 52.

[62] Exhibit JJS-1page33.

[63] Id., at page 34. 45 ENTERGY TEXAS 353-TRANSMISSION STATION EQUIPMENT(1984) 100 90 (f) .... g c: 0:: Q) > .... 80 (.) Q) 0:: 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

[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 accounting for its transformers, which should have indicated a longer ASL compared to the industry average since many utilities actually retire transformers when they move such equipment from one location to another. In addition, while Mr. Spanos' notes indicate that there is an expectation for a shorter lives in the future for transformers, this is an argument that has been utilized in the industry for the past 20 or 30 years, yet the industry has demonstrated increasing life expectancy for substation equipment as more empirical data has been obtained. Therefore, the 52-year ASL is more indicative of the Company's actual experience, better reflects industry expectations, and is more representative of the type of equipment in the account. Q. WHAT IS THE IMP ACT OF YOUR RECOMMENDATION? A. My recommendation of a 52-year ASL on a standalone basis results in a $1,462,347 reduction to depreciation expense based on plant in service as of December 31, 2008. Account354 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 354 - TRANSMISSION TOWERS? The Company proposes a 50-S4 life-curve combination. 66 A. Q. WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL? This is an account where the historical data is not relied upon and Mr. Spanos reverts to A.

[65] Response to Rose City 1-15 Addendum page 46.

[66] Exhibit JJS-1 page 52. 47 WHAT IS THE BASIS FOR YOUR RECOMMENDATION? 1 Q. 2 A. First, while the historical data provides an extremely short "stub curve", it does provide an indication for a long ASL given the very limited level of retirement activity that has transpired during over 50 years of data. 67 In addition, Mr. Spanos' industry database indicates a mean, median and mode of 63, 65 and 65 years, respectively. 68 Indeed, the industry data that would have formed possibly a major portion of Mr. Spanos' 'judgment" indicates that the use of a 50-year or lower ASL is very limited. Therefore, all indications of available data indicate that a value in the mid 60-year range is by far superior to the Company's proposed 50-year ASL. Moreover, the Company proposed a 55-year ASL for Account 355 - Transmission Poles. On a predominant basis, the industry recognizes that transmission towers have longer expected ASLs than do transmission poles. In this case, Mr. Spanos also failed to take this relationship into his judgmental decision making process. Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 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? The Company proposes a 55-R3 life-curve combination. 69 23 A.

[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 COMP ANY'S PROPOSAL? 2 A. No. The Company's proposal is artificially short; therefore, I recommend a 59-R2.5 life curve combination. Q. WHAT IS THE BASIS FOR YOUR RECOMMENDATION? A. As shown in the graph below, my recommendation results in a better fit to the OLT in the significant portion of the curve that Mr. Spanos referenced in his testimony. Indeed, Mr. Spanos sacrificed a better fitting relationship during periods beginning around age 8 years in order to strive for a better match during the age intervals of approximately 25 years through 35 years. The problem with Mr. Spanos' election to discount the earlier portion of the curve in an effort to match a later portion of the curve sacrifices exposures in the $40-$70 million range for better fitting exposures in the $15-$40 million range. 71 As can be seen in the graph be]ow, my recommendation is a superior fit during the first approximate 24 years of age.

[71] Exhibit JJS-1pages104-105. 49 ENTERGY TEXAS 355 - TRANSMISSION POLES AND FIXlURES (1954) 100 90 a::: - 0 en 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) 59R2. 5 __..._ 55R3 Actual 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,

[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? The Company proposes a 53-R2.5 life-curve combination. 73 10 A. 11 12 Q. WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL? For this account, the Company relies on Mr. Spanos' claim relating to a good to excellent 13 A. indication from the statistical analyses. 74 I 14 15 16 Q. I DO YOU AGREE WITH THE COMP ANY'S PROPOSAL? 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 the graph below, both Mr. Spanos' proposal and my recommendation are both good fits 19 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

[73] Exhibit JJS-1 page 52.

[74] Id., at page 33. 51 ENTERGY TEXAS 356 - TRANSMISSION OVERHEAD CONDUCTORS AND DEVICES (1954) 100 90 ... c: C/) a: 0 > Q) 80

[0] ,_ > 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

[75] Exhibit JJS-1 page 51. 52 I Q. WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL? 2 A. Given that there have been no retirement activity reflected in the Company's historical database, this is an account where the Company relied on judgment and other undefined parameters. Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? A. No. The same situation as discussed for Account 350 - Transmission Land Rights also pertains to Distribution Land Rights. The Company's selection would have land rights retiring long before the end of a single life cycle is reached for various other distribution accounts. Thus, on its face, the Company's proposal is illogical. Therefore, I recommend a 85-R4 life-curve combination, taking into account land rights must exist for at least one complete life cycle relating to the investment that resides upon it. As time passes this estimate will have to be expanded in recognition that retirements will not occur as additional new plant is placed on the same land rights and that new investment must also complete its life cycle. Q. WHAT IS THE IMP ACT OF YOUR RECOMMENDATION? A. My recommendation for an 85-year ASL results in a $120,195 reduction in depreciation expense based on plant as of December 31, 2008. Account 362

[76] Exhibit JJS-1page53.

[77] Id., at page 34. 53 1 Q. DO YOU AGREE WITH THE COMP ANY'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 during the age interval of zero (0) to 0.5 year.

[78] It is unusual to have such significant 8 9 levels of infant mortality in comparison to older aged equipment. Indeed, the vast majority of this infant mortality incurred in 1954.

[79] No other infant mortality of this IO magnitude has transpired in the subsequent 54 years. Therefore, proper judgment should have recognized this event as an outlier and normalized it in the database. The reality is that utilities, absent unusual events, are not expected to purchase and install equipment that is expected to fail immediately upon installation to any great extent. Thus, the Company's historical OLT reflects an artificial reduction at an early time frame given that such data is being used as a predictive tool for future expectations. The largest level of retirement activity during any age interval occurred beginning at age interval 6.5 years.

[80] This annual level of retirement activity is approximately ten times the level of retirement activity in the age intervals immediately preceding or following. Again, this is the type of activity that should have caused an analyst to question the

[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 relevant to a 8MV A stored magnetic energy superconductor unit located at a substation. The Company could not provide any support for why a retirement of this magnitude for this type of equipment is expected to reoccur on a similar basis in the future. 83 Therefore, the impact of what is a single, but large, unusual event should have been normalized in the Company's analysis. Indeed, Mr. Spanos, who claims constant reliance on judgment, apparently failed to even recognize that his own database of other utilities would have indicated that his proposed 40-year ASL for this account was well below the mean, median or mode for his industry range. 84 This discrepancy between ETI and the industry should have resulted in this transaction being adjusted prior to the curve fitting process had proper judgment been employed. As set forth in the graph below, I have normalized only the outlier at the 6.5 age interval. 85 As can be seen, my recommended 46-SO life-curve combination is a superior or equal fit to all data points when compared to Mr. Spanos' proposal. Moreover, my recommendation better matches Mr. Spanos' industry data and is consistent with the cradle to grave type accounting employed by the Company for transformers and other major equipment at substations, as identified in Mr. Spanos' site visit notes. 86 My recommendation is conservative given the fact that the curve matching process still incorporates atypical hurricane activity that should have also been normalized.

[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 a:: - g c:: 80 Q)

[0] > ~ Q) a:: a. 70 ::::> en I 60 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

[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 analysis. 88 4 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- curve combination. The Company's historical data included $2.8 million of unusual retirement activity in the age interval 0.5 that occurred in 2008, the year in which Hurricane Ike hit. 89 The retirement activity at age intervals 0.5 is significantly greater than any other time frame and is atypical in nature. Therefore, at a minimum, the OLT would need to be normalized for such activity. As shown in the graph below, my life- curve combination is a better match to the historical data minimally for the first 30 years, and then again beginning at approximately 44 years of age. If the remaining retirements associated with recent hurricane activity were also removed from the data, it would raise the OLT and make my recommendation even a better fit than set forth in the graph below.

[88] Id., at page 34.

[89] Response to Rose City 13-11. 57 ENTERGY TEXAS 365- DISTRIBUTION OVERHEAD CONDUCTORS & DEVICES (Normalized) 100 :-.. ~ 90 ~ ~ 80 ~ ~ ~ 70 Cl) ~ 0:: ~ .., .+J 0 c 60 > Q) ' e 6; ..... Q) 50 a.. ::::> ~ Cl) 40 ~ ~ 30 ~ ~ a_ 20 ~ ~ ~ 111 111 111 111 Ill 111 Ill 111 111 111 111 111 111 111 JUI 111 111 111 10 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

[90] Response to Rose City 1-15 Addendum at page 49. 58 study. Overall, my recommended 39-year ASL is conservative, considering actual 1 2 historical data even before normalization for all hurricane activity. 3 4 Q. WHAT IS THE IMP ACT OF YOUR RECOMMENDATION? A. My recommendation for 39-year ASL results in a $1,103,876 reduction in depreciation 5 6 expense based on plant as of December 31, 2008. 7 Account 366 8 9 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 366 - IO DISTRIBUTION UNDERGROUND CONDUIT? 11 The Company proposes a 50-R2 life-curve combination. 91 A. 12 13 Q. WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL? 14 15 A. This is an account where the Company did not rely on the statistical analysis it performed, but rather relied on unidentified judgment and other factors. 92 16 17 Q. DO YOU AGREE WITH THE COMP ANY'S PROPOSAL? 18 A. No. First, it must be noted that the existing ASL for this account is 60 years. Thus, the 19

[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? My recommended 60-year ASL results in a $182,339 reduction to depreciation expense 6 A. based on plant as of December 31, 2008. 7 8 9 Account 368 10 11 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 368 - 12 DISTRIBUTION LINE TRANSFORMERS? The Company proposes a 29-SO life-curve combination. 95 13 A. 14 15 Q. WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL? For this account the Company relied on what it believed to be a good or excellent 16 A. statistical fit for the historical data. 96 17 18 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? No. The Company's proposal results in one of the shortest ASLs for any utility in the 19 A.

[95] Exhibit JJS-1 page 53.

[96] Id., at page 34. 60 ASL for this account is 39 years, thus the Company is proposing a value 10 years shorter than the existing level. Even if this was a reasonable prediction, which it is not, a degree of gradualism may be warranted. More significant to the concept for a longer ASL than proposed by the Company is the fact that the Company has included significant retirement activity associated with hurricane-related recent events. Normalization of the data to remove hurricane activity would result in raising the OL T from its current position, thus resulting in a longer ASL. Indeed, just removing the 2008 retirement activity for ages 0.5 year through 5.5 years, corresponding to just the 2002-2007 vintage additions, increases the "head" or top portion of the survivor curve by approximately 0.6 of a percentage point. This level of increase is meaningful. In addition, Mr. Spanos states in his site visit notes that the Company has historically overloaded its line transformers. This is not a typical practice for an extended period of time and thus, future life expectancy should be longer than that experienced historically. 97 Yet another consideration is the fact that Mr. Spanos' industry database indicates that a 29-year ASL would be basically at the extreme low end of the industry range. Even

[97] Response to Rose City 1-15 Addendum at page 49. 61 1 Q. WHAT IS THE IMP ACT 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 - DISTRIBUTION SERVICES? 8 9 A. The Company proposes a 27-U life-curve combination for both underground and overhead services. 98 10 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 for his proposal. 99 14 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

[98] Exhibit JJS-1 page 53.

[99] Id., at page 34.

[100] Response to Rose City 1-17. 62 J industry expectations.

[101] In other words, the industry indicates a longer ASL than the existing 36-year level, definitely not a reduction to the 27-year level as proposed by the Company. Next, review of Mr. Spanos' industry database further raises concern regarding the proposed "L4" Iowa Survivor Curve. In this existence, Mr. Spanos' judgment relating to what he has observed from the industry and the type of plant in this account should have resulted in further investigation. Indeed, not a single other industry value relies on "L4" dispersion, or for that matter any "L" pattem.

[102] Another consideration that is not addressed by Mr. Spanos is the movement towards more underground rather than overhead services. As reaffirmed by Mr. Spanos' industry database, underground services are generally expected to have a longer ASL than 3 The percent investment in underground services has grown faster overhead services. l0 than for overhead services in the last I 5 years.

[104] This fact should have also indicated a longer ASL. Finally, the fact that the Company's data includes hurricane related retirements further demonstrates that a longer ASL than indicated by the OLT is appropriate.

[101] Id. r

[102] Id.

[103] Id. I

[104] 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? The Company proposes a 44-R2.5 life-curve combination.

[105] 9 A. 10 11 Q. WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL? The Company relies on the results of its statistical actuarial analysis for this account.

[106] 12 A. 13 DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 14 Q. 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

[105] Exhibit JJS-1page53.

[106] Id., at page 34.

[107] Response to Rose City 1-41. 64 the Company's business.

[108] This type of transaction is atypical and should not negatively l affect current customers through the depreciation process. Relying on the remainder of the OLT, but eliminating this unusual transaction, would require a substantial increase in ASL. In addition, the majority of the investment in this account is associated with office buildings and other structures that the Company owns rather than leases.

[109] Office structures, warehouses and similar facilities can normally have life expectancies approaching 75 to 100 years or more. Taking into account that the investments still require a replacement of air conditioning systems, roofs and others components would reduce the dollar-weighted ASL. Mr. Spanos' industry database indicates numerous ASLs for investment in this account that still exceed 50 and even 60 years. In addition, Mr. Spanos' site visit notes state that buildings are generally "concrete slab with steel structures on top."uo Steel buildings on concrete slabs can easily be expected to achieve 50 or even 60 years on a dollar-weighted basis. Therefore, my recommended 53-year ASL is conservative in favor of the Company.

[108] Response to Rose City 13-18.

[109] Response to Rose City 1-41.

[110] 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 over which benefits will be realized. u 2 The amortization period is based on ''judgment 3 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 service life estimates previously used for the asset under depreciation accounting." 113 6 7 8 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? 9 A. No. The Company's proposal is artificially short; therefore, I recommend a IO-year I 0 amortization period. First and foremost, this is an account where the Company has 11 already experienced an acceleration of amortization expense given that many vintages are already fully accrued, yet the plant is still in service.

[114] What is clear is the 5-year 12 13 amortization clearly understates the expected useful life of the facility. Moreover, Mr. 14 Spanos' has failed to provide any judgmental basis that would render a 5-year 15 amortization period for this investment as realistic and appropriate. 16

[112] Exhibit JJS-1 page 46.

[113] Id.

[114] Exhibit JJS- l page 302. 66 information software system was assigned a 5-year value in Mr. Spanos' database. 2 Indeed, other utilities are employing values up to 15 years for major customer 3 information software systems. Therefore, my recommendation to retain the existing 10- year amortization period is conservative and complies with Mr. Spanos' stated basis for 4 5 his judgmentally derived proposal. 6 7 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? 8 A. My recommendation to retain the existing 10-year life would result in a $1,423,792 reduction to amortization expense based on plant as of December 31, 2008. In addition, a 9 10 remaining life annual amortization rate should be set at 7. 7%. 11 12 Account 394 13 14 Q. WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 394 - GENERAL 15 TOOLS, SHOP & GARAGE EQUIPMENT? The Company proposes a 15-year amortization period. 115 16 A. 17

[115] Exhibit JJS-1 page 53.

[116] Id., at page 306. 67 The second item considered by Mr. Spanos referenced in his testimony is what other utilities are using. Again, Mr. Spanos' proposed 15-year amortization period falls short of his own industry database. Indeed, the predominant value Mr. Spanos reflects in his industry database is 25 years, with very few utilities employing something less than 20 years.

[117] Thus, Mr. Spanos' claim of reliance on service lives used by other utilities is contrary to his artificially short proposed amortization period. Relying on the parameters, which form the basis of Mr. Spanos' judgmental approach, would require a conservative estimate of a 20-year amortization period, with a possibly more appropriate level of 25 years. However, in order to remain conservative, I am recommending the retention of the existing 20-year life. Q. WHAT IS THE IMP ACT OF YOUR RECOMMENDATION? My recommendation for a 20-year amortization period results m a reduction in 14 A. amortization expense of $187 ,514 based on plant as of December 31, 2008. In addition, a 15 16 remaining life rate should be set at 4.12%.

[117] Response to Rose City 1-17. m Exhibit JJS-1 page 53. 68 Q. DO YOU AGREE WITH THE COMP ANY'S PROPOSAL? A. No. In this case, the proposed amortization period is artificially short. Therefore, I recommend a 15-year amortization as a conservative value. A review of the Company's actual historical data identifies that the use of the 10-year amortization period will begin allowing the Company to more than fully accrue the investment in this account. 119 In fact, as of now, portions of the Company's original cost are over-amortized. Turning to Mr. Spanos' industry database, one would also find that my recommended 15-year amortization period is by far more prevalent than any other value reported. 120 Relatively few utilities in Mr. Spanos' database utilize amortization periods as low as 10 years. 121 Another consideration for recommending a 15-year amortization period is the fact the existing combined Account 397 life expectancy is 19 years, as approved in Docket No. 16705. Therefore, given the fact that Account 397.2 corresponds to microwave equipment, one might expect a shorter life span for the remaining investment reflected in Account 397.1, but not to a level of only 10 years as proposed by Mr. Spanos. Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? A. My recommendation for a 15-year amortization period results in a reduction of $167,904

[119] Id., at page 309.

[120] Response to Rose City 1-17.

[121] Response to Rose City 1-17. I

[122] Exhibit JJS-1page53. 69 I Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL? No. Again, the Company's proposal is artificially short. Therefore, I recommend a 20- A. year amortization period for the investment in this account. First, it must be noted that the existing life expectancy for this account is 19 years, as set in Docket No. 16705. Given that this account is now segregated between microwave equipment and remaining communication equipment, and the fact that the remaining communication equipment has a lower overall life, the life expectancy for microwave equipment should be greater than the existing 19-year time frame. Therefore, this portion of Mr. Spanos' stated judgmental basis supports a longer amortization period than what he has proposed. Turning to industry data, Mr. Spanos only identifies one utility with an equivalent sub account identification.

[123] That utility is Chugach Electric Association, which reported a 15-year period. This is a generation cooperative in the Anchorage, Alaska area. Amortization of microwave equipment subject to the weather conditions in Alaska can reasonably be assumed harsher than reflected in the lower 48 states. Therefore, from a judgmental basis associated with industry information, Mr. Spanos should have proposed a longer amortization period.

[123] Response to Rose City 1-17.

[124] Exhibit JJS-1 page 310. 70 1 Company cannot be allowed to unilaterally and arbitrarily decide to cease the booking of 2 amortization or depreciation when it believes that an account is fully accrued. 3 4 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? My recommendation for a 20-year amortization period results in a reduction in 5 A. 6 amortization expense of $1,136,473 based on plant as of December 31, 2008. In addition, 7 my recommendation results in an amortization rate of 1.67%. 8 6. Mass Property Net Salvage 9 10 Q. WHAT ISSUE DO YOU ADDRESS IN TIDS PORTION OF YOUR 11 T ESTIMONY? 12 A. I will address the Company's request for a significant increase in revenue requirements 13 associated with more negative net salvage for the Company's mass property plant 14 accounts. After review of the underlying information I recommend retention of the 15 existing net salvage levels. 16

[125] Exhibit JJS-1 pages 188-207 and Direct Testimony of Mr. Spanos at page 22.

[126] Direct Testimony of Mr. Spanos at page 22.

[127] ld.

[128] Exhibit JJS-1 page 37. 71 1 Q. DID MR. SPANOS PROVIDE ANY DETAILED INFORMATION BY ACCOUNT IN ms TESTIMONY OR DEPRECIATION STUDY THAT WOULD IDENTIFY 2 HOW HE SPECIFICALL y ARRIVED AT ms PROPOSED v ALUES FOR EACH 3 4 INDIVIDUAL MASS PROPERTY ACCOUNT? No, other than a partial explanation for Account 365 used as an example in his 2008 5 A. Study.

[129] This is one of the accounts where Mr. Spanos claims he relied heavily on the statistical information derived from his 5-year database. Even for this account, Mr. Spanos admits that the cost of removal fluctuated quite a bit throughout the 5-year period and that such fluctuations "were a result of storms that forced higher labor costs for removing assets."

[130] (Emphasis added). Mr. Spanos then compared the 5-year average to the range of what other electric companies estimated for this account. However, when his comparison with the industry data pointed out that ETI's 5-year average of a negative 50% was not only outside the industry range but was also more than double the midpoint of the range employed by other utilities, Mr. Spanos then concluded that the historical statistical analysis was adequate, taking into account the "conditions of the region."

[131] Thus, Mr. Spanos' single narrative example added confusion rather than clarity given that he totally disregarded his own industry data even though for Account 352 he did the

[133] http://www.hurricanecity.com/city/portarthur.htm

[134] Texas Hurricane History, National Weather Service.

[135] Response to Rose City 1-21. 73 Indeed, while Mr. Spanos claims his allocation is "a little more than a gut" feeling, it "is 1 not logged" anywhere and only resides in his head. 136 2 3 4 Q. ARE THERE ERRORS IN THE COMP ANY'S PROCESS OF ASSIGNING FUNCTIONAL VALUES TO INDIVIDUAL PLANT ACCOUNTS? 5 6 A. Yes. Not only are there reversal of signs (i.e., reporting values as being negative when they should have been positive) in the data, but there are theoretically impossible values 7 reflected in the data. 137 8 9 TURNING TO THOSE INSTANCES WHERE MR. SPANOS DID NOT RELY TO 10 Q. 11 ANY EXTENT ON TIIE CLAIMED. IDSTORICAL STATISTICAL ANALYSIS, 12 DID HE PROVIDE ANY SPECIFIC DOCUMENTED SUBSTANTIATION FOR 13 EACH ACCOUNT? 14 A. No. This is important given that 60% of the investment falls into this category. 15 16 Q. DOES MR. SPANOS CLAIM THAT HE MAINTAINED ALL SUCH INFORMATION SUPPORTING ms BASIS IN ms HEAD? 17

[136] Deposition of Mr. Spanos on April 20, 2010 at TR 32-33.

[137] Response to Rose City 1-21 Attachment.

[138] Deposition of Mr. Spanos on April 20, 2010 at TR 57-58.

[139] Id., at TR 57.

[140] Id., at TR 58. 74 Q. WAS MR. SP ANOS ABLE TO DEMONSTRATE AN IMPRESSIVE ABILITY TO RECALL SPECIFIC ITEMS OF INFORMATION DURING ms DEPOSITION AS IT RELATES TO SPECIFIC FACTORS IN THE ETI STUDY? A. No, quite the contrary. On any specific item for which Mr. Spanos was requested to provide detailed explanations, he could not recall what specific information might have been given to him from Company personnel or other factors.

[141] The only documented items of information that may have impacted Mr. Spanos' judgment is set forth in his limited site visit notes.

[142] HAVE YOU REVIEWED THE SITE VISIT NOTES THAT MR. SPANOS Q. PROVIDED IN DISCOVERY THAT SHOWS THE TOTALITY OF ms DOCUMENTED JUDGMENT? Yes. 14 A. 15 DID YOU FIND THAT THE SITE VISIT NOTES PRODUCED ADEQUATE 16 Q.

[141] Id., at TR 106-107 for example.

[142] Response to Rose City 1-15. 75 includes numerous major hurricanes as though they would continue to occur on an equally frequent basis in the future as they did in the limited 5-year period, the allocated data includes errors, the industry data relied upon is ignored when it interferes with the desired results, or the industry data reflects ranges so wide as to make the industry data meaningless as a valid basis for selection of any given value. Finally, the Company has failed to provide specific support for individual account proposals, even when specifically requested to provide such information. Thus, the interveners and the Commission are left with proposals by account without any discemable basis. The presentation by the Company leaves the parties with a ''take it or leave it" approach to its proposals. Q. WHAT DO YOU RECOMMEND? A. Given the Company's presentation and available data, I believe the only realistic option left to the interveners and the Commission is to take up the Company's offer of"take it or leave it." I recommend leaving the existing net salvage proposals in place as the best alternative left at this point and time. I further recommend that the Commission order the Company to develop and justify a net salvage database by account for an historical period

[143] Deposition of Mr. Spanos on April 20, 2010 at TR 140. 80 1 Q. WHAT WAS THE ANOMALY TO WlllCH MR. SPANOS REFERS? 2 A. On Exhibit JJS-1 at page 258, Mr. Spanos presents his ELG calculation for Account 352 3 - Transmission Structures & Improvements. When asked why the remaining life for the 4 2008 vintage addition of 36.67 years was shorter than the remaining lives for older 5 vintage additions, Mr. Spanos admitted that that was "slightly unusual" and represented a "slight anomaly." 144 Indeed, having a shorter remaining life for the newer vintages is 6 7 more than a slight anomaly - it is a theoretically impossible situation. 8 9 Q. IS TIDS THE ONLY ANOMALY REFLECTED IN MR. SP ANOS' STUDY? No. Moreover, the claimed "slight" anomaly grows into a major anomaly in other I 10 A. 11 accounts, such as for Account 365. In Account 365 - Distribution Overhead Conductors 12 and Devices, the remaining life for vintage addition 2008 is only 15.13 years, then 13 increases to 18.38 years for the 2007 vintage additions. In fact, as set forth in the table 14 below, the remaining life increases for each vintage addition from 2008 back through 15 2001. The remaining life then decreases for the 2000 addition, but turns around once 16 again and increases for the 1999 vintage addition. Not only do we have a major anomaly

[145] Exhibit JJS-1page289-291.

[146] Exhibit JJS-1 pages 276-278 and page 298. I 84 I 1 for Account 364 down to the one hundredth of a decimal point level of accuracy. Again, 2 the possibility of another coincidence of this situation is so remote as to defy credibility. 3 Simply put, Mr. Spanos' attempt to divert attention from his anomaly, which is an error, 4 and claim that it is a refinement of the annualized rate is disingenuous. The real answer is 5 Mr. Spanos has a problem in his calculation procedure and refuses to admit to such 6 problem by employing deception in his explanative response to request for information 7 Rose City 24-38. 8 9 Q. WAS MR. SPANOS REQUESTED TO PROVIDE A NARRATIVE IO EXPLANATION ALONG WITH NUMERICAL EXAMPLE AND ALL ACTUAL 11 FORMULAS ASSOCIATED WITH HIS ELG COMPUTER PROGRAM THAT 12 DEMONSTRATES HOW THE ANOMALY COULD OCCUR FOR CERTAIN 13 ACCOUNTS? Yes.

[147] However, Mr. Spanos failed to provide a single formula or numerical example 14 A. 15 that supports the validity of his claimed refinement.

[147] Response to Rose City 24-44. 85 1 Q. IS THERE ADDITIONAL SUPPORT FOR WHY THE COMMISSION SHOULD 2 NOT RELY ON THE FAULTY ELG PROCEDURE? Yes. Given the extensive and technical nature of the problems to be addressed with the 3 A. 4 ELG procedure, I have attached Appendix B to my testimony, which addresses in further 5 detail problems with the ELG procedure. 6 7 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION TO RELY 8 EXCLUSIVELY ON THE ALG CALCULATION PROCEDURE? 9 A. The standalone impact of relying on the ALG calculation procedure for mass property 10 plant accounts results in a $19.3 million reduction in annual depreciation expense based 11 on plant as of December 31, 2008. 12 8. Remaining Life Method 13 14 Q. WHAT DOES THIS PORTION OF YOUR TESTIMONY ADDRESS? 15 A. This portion of my testimony addresses the Company's remaining life calculation.

[148] Remaining Life Rate= (100-Net Salvage-Reserve)/Average Remaining Life. Rule 25-6.0436(l)(e), F.A.C.

[149] Order No. PSC-10-0153-FOF-EI in Docket Nos. 080677-EI, 090130-EI at pages 26 and 27. 88 1 2 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION? The impact of my recommendation is reflected in the standalone mass property life 3 A. 4 recommendations and the standalone ALG calculations. Finally, the correct calculation is 5 reflected in the combined impact adjustments set forth in my testimony. SECTION III: FULLY ACCRUED DEPRECIATION 6 7 8 Q. WHAT DO YOU ADDRESS IN THIS PORTION OF YOUR TESTIMONY? 9 A. I address the Company's action to cease the booking of depreciation in instances where an account or sub-account is unilaterally assumed to be fully accrued. 10 11 12 Q. WHO HAS THE AUTHORITY TO CHANGE DEPRECIATION OR 13 AMORTIZATION RATES? 14

[150] Response to Rose City 1-19. 90 I salvage can be either positive or negative. This approach recognizes that while recovery 2 of net depreciable investment less net salvage may be under or over recovered, the intent 3 is to allow only I 00% recovery, not more or less. 4 5 Q. WHAT DID TmS COMMISSION ORDER REGARDING THE APPLICATION 6 OF DEPRECIATION FOR Tms COMP ANY? 7 A. In Docket No. 16705, the Company's last litigated rate case, the Commission ordered the 8 adoption of "Staff's proposed depreciation rates."m (Emphasis added). 9 10 Q. DOES THE COMP ANY ADMIT THAT IT CEASED USING THE COMMISSION 11 APPROVED RATES FROM DOCKET NO. 16705? Yes. The Company admits that it "stopped booking depreciation" for 3 accounts.

[152] 12 A. 13 14 Q. WHO AT THE COMPANY MAKES THE DECISION AS TO WHEN AN 15 ACCOUNTBECOMESFULLYACCRUED?

[151] Docket No. 16705 FOF 190.

[152] Response to Rose City 13-32c.

[153] Response to Rose City 13-32b. 1s4 Id.

[155] Id., at (a). 1s6 Id. 91 I IS THE COMP ANY CORRECT IN ITS BASIS? 1 Q. 2 A. No. As part of the same series of definitions relied upon by the Company in the USOA, there are general instructions which identify under depreciation accounting the reference to a rate. The USOA states that utilities "must use percentage rates of depreciation that are based on a method of depreciation that allocates in a systematic and rational manner."

[157] The Company takes a unique interpretation of these series of items, which then allows it the unilateral authority to change a depreciation rate that has been approved by the Commission through the back door mechanism of an algorithm built into a software program that has never been approved by the Commission. This unique interpretation of the USOA and hidden algorithms within software programs violate the Commission's orders adopting depreciation rates in prior proceedings. Q. WOULD THE COMPANY'S ACTIONS BE APPROPRIATE IF IT WERE AN UNREGULATED COMPANY? 15 A. Yes. However, since ETI is a regulated utility, its actions are inappropriate because

[158] PUCT Docket No. 10894, Examiners' Report pages 106-110.

[159] PUCT Docket No. 10894 Finding of Fact 288.

[160] October 18, 2004 Hadco International Appraisal & Consulting Services. 94 1 approved by the Louisiana Public Service Commission. If this were to occur, or if 2 deregulation is eventually implemented for the Company, Texas retail customers stand to 3 lose the value of the facility they have already paid for and were previously promised. 4 Thus, Texas retail customers may lose their share of the current $100 million gross 5 salvage attributable to the SGSF unless action is taken. 6 7 Q. WHY IS IT APPROPRIATE TO TAKE ACTION IN TIDS PROCEEDING? 8 A. In Docket No. 10894, this Commission specifically afforded the Company recovery for 9 the capital costs of constructing the gas storage facility even though it did not own the facility. 161 This action was taken in spite of the Company's admission that if it had I 0 constructed the facility itself it would have been subject to base rate treatment. 162 The 11 12 Company could not build the facility itself due to budgetary constraints at the time the 13 project to construct the gas storage facility became available. The Commission granted 14 the Company special treatment based in part on the fact that customers were expected to

[161] PUC Docket 10894.

[162] Id., at Finding of Fact 308.

[163] Id., at Finding of Fact 310. 95 Q. WHY DO YOU BELIEVE THAT THE VALUE OF THE FACILITIES WILL 1 INCREASE IN THE FUTURE? 2 A. First and foremost, the value of the facilities increased by a factor of 2.5 times its original 3 $40 million cost in a little over a decade ($100 million + $40 million = 2.5). This increase 4 in value has occurred in large part due to the change in the natural gas industry and the 5 resulting prices that suppliers have and can demand for their product. The price of gas has 6 7 reached all-time highs in the last several years and the fact that the gas market is unstable, coupled with the concern for air quality associated with coal-fired generation and 8 9 consideration of a return to a more robust economic market, results in the conclusion that the future for gas prices will continue to be volatile and most likely be at a higher level 10 than experienced during the 1990s and early 2000s. As gas prices increase in cost over 11 12 time, the value of the gas storage facility further increases. Thus, in another 5 or 10 years the gas storage facility may actually be valued at something much higher than the recent 13 estimate of $100 million to another entity. In the event the Commission opts to retain the 14

[164] Response to Rose City 1-16.

[165] 798 s. w. 2d 560.

[166] ld. I t67 Id. 97 I shareholders over the years, and any extraordinary burdens borne by l the ratepayers in connection with that asset. 2 3 4 Q. DID YOU CONSIDER VARIOUS FACTORS? 5 A. I have considered numerous factors. First while ETI did not own the plant prior to January 2005 and thus it was obviously not included in rate base, the treatment afforded 6 7 the Company by the Commission was in fact superior to rate base treatment. As 8 previously noted, the Commission granted the Company the right to recognize all 9 construction costs and operating costs as reconcilable fuel. By doing so, it allowed the 10 Company to pass basically all financial burdens on to customers and without the normal 11 regulatory lag and guaranteed cost recovery. In addition, the costs incurred by SGT for 12 property taxes, operation and maintenance expenses, etc. were also passed on to the 13 Company. The Company in tum included such costs as reconcilable fuel costs, which 14 were then passed on to customers. Once again, customers paid all operating and tax 15 impacts of the facility.

[168] Mr. Harrington's rebuttal testimony at WEH-7 in Docket No. 10894. 100 1 Q. TURNING TO RELATING YOUR SECOND ISSUE TO 2 INTERGENERATIONAL INEQUITY, WHAT DO YOU RECOMMEND? 3 A. I recommend correcting the significant level of intergenerational inequity that currently 4 exists by amortizing the future service value over a four-year period in conjunction with 5 corresponding depreciation treatment of the estimated remaining life of the facility. This 6 treatment will eliminate the "free ride" future customers will enjoy given the full, but 7 accelerated, depreciation realized for the initial capital costs. 8 9 Q. WHY ARE CUSTOMERS ENTITLED TO A CREDIT FOR PRIOR 10 ACCELERATED RETURN OF CAPITAL OR DEPRECIATION PAYMENTS? 11 A. Had the SGSF been afforded normal base rate treatment rather than the superior fuel 12 treatment, the Company's books would already reflect the "Credit Payments" in the 13 APFD (Account 108) as a credit to rate base. Given that customers were required to pay 14 off the facility on an accelerated basis to meet the construction related finance

[169] Production demand allocation factor of 42.5% as noted in response to Rose City 2-6(c) times the $40 million initial cost.

[170] $17 million amortized over 4 years equals $$4,250,000, less $17 million depreciated over 35 years equals I $485,714. 101 1 retail customers with approximately $1 billion of excess or prior accelerated depreciation over a four-year period. 171 2 3 4 Q. WHAT ANNUAL LEVEL OF DEPRECIATION WILL CUSTOMERS BE REQUIRED TO INCUR ASSOCIATED WITH YOUR RECOMMENDATION? 5 6 A. As part of my recommendation customers will be required to pay $485,714 of annual 7 depreciation expense in order to extinguish the $17 million rate base credit over the 35- 8 year remaining life I am recommending. 9 WILL FUTURE CUSTOMERS HAVE TO PAY FOR A PORTION OF YOUR IO Q. RECOMMENDATIONS? 11 12 A. Yes. After the proposed 4-year amortization is over and the Company files for a change in base rates, future customers will begin paying a return and depreciation on the 13 14 $17million portion of my recommendation for the remaining life of the facility. This

[171] FPSC Docket Nos. 080677-EI and 090079-EI, a FP&L and Progress Energy Florida case, respectively.

[172] Direct testimony of Mr. Wilson at page 4.

[173] Id. 102 amortize this claimed $83.7 million ($64.4 million + $19.3 million) change in reserve position over a 20-year period, for a $4.18 million annual expense. The second component of the Company's proposed annual accrual is $5,270,000, which represents the Company's estimated annual ongoing storm losses.

[174] In addition to these two components, ETI also requests $25,278,210 in rate base, to be amortized over 5 years at an annual rate of $5,055,642, associated with a proforma adjustment for hurricane securitization cost that were removed from the storm reserve.

[175] This portion of my testimony addresses my recommendations to eliminate significant portions of the claimed historical reserve deficit, reduce the projected reserve target level, reduce the annual estimated storm loss expense, and assign storm reserve treatment to the proposed hurricane securitization proforma adjustment. As summarized in the table below, the combined impact of my recommendations reduces the Company's requested $9.45 million annual revenue requirement by $7,703,810 and also reduces rate base by $45,867,967. I also recommend increasing the storm threshold level from $50,000 per

[174] Id., at page 5.

[175] Testimony of Mr. Wright at pages 19-20 and ETI Adjustment AJIS.10. 103 Q. DOES THE COMMISSION PERMIT SELF-INSURANCE BY UTILITIES? A. Yes. The Commission has implemented Substantive Rule 25.23l(b)(l)(G) relating to a self-insurance plan for storm damages. The establishment and operation of the insurance reserve is intended to produce a less costly approach to dealing with storm damage, which could not have been reasonably anticipated, than would be the case if the Company purchased commercial insurance. Q. DOES THE COMPANY CURRENTLY HAVE A SELF-INSURANCE PROGRAM? A. Yes. In fact, the issues addressed in this proceeding cover the changes in the Company's self-insurance reserve subsequent to the settlement in Docket No. 34800 and in the Company's last fully litigated rate case, Docket No. 16705.

[176] Docket No. 16705 FOF 146.

[177] Id., atFOF 147.

[178] Docket No. 34800 Settlement Term Sheet Item 8. 104 Q. WHAT DOES THE COMPANY CLAIM HAS TRANSPIRED TO THE STORM 2 RESERVE SUBSEQUENT TO DOCKET NO. 16705? 3 A. The Company claims that it has incurred storm losses from 155 different storms, each of which exceeded $50,000 of charges in aggregate. 179 In addition, the Company increased 4 5 the reserve on an annual basis for the $1.651 million annual insurance accrual through 6 2008, and then by $3.651 million annually beginning in 2009. 7 8 Q. WHAT ARE THE VARIOUS COMPONENTS OF THE SELF-INSURANCE 9 RESERVE EXPENSE THAT REQUIRE INVESTIGATION? 10 A. The Commission has identified the annual level of contributions until the amount was increased effective January I, 2009 in association with Docket No. 34800. All other 11 12 components that affect the insurance reserve level and annual expense are subject to review and justification. 13

[179] Response to Rose City 5-1.

[180] Direct Testimony of Mr. Wilson at page 5. The precise claimed deficit is $64,355, 152. I

[181] Deposition of Mr. Wilson on April 22, 2010 at TR 12. 105 l Q. DID MR. WILSON INVESTIGATE THE REASONABLENESS OR NECESSITY 2 OF ANY OF THE EXPENSES THAT WERE INCLUDED IN THE CLAIMED $64 3 MILLION RESERVE DEFICIT? No.182 4 A. I 5 6 Q. DID THE COMPANY PRESENT ANY DETAILED ANALYSES 7 DEMONSTRATING THE VALIDITY OF THE COSTS REFLECTED IN ITS 8 STORM RESERVE? 9 A. No. There was no presentation by the Company that demonstrates it has only included l 0 prudent, reasonable and necessary costs in its storm reserve. In fact, the loss-run data 11 supporting the costs included in the storm reserve for the periods prior to 1996 were not 183 12 retained. Moreover, the Company did not provide any documentation that 13 demonstrates that the labor charges reflected in the storm reserve are not already being

[182] Id., at TR 12 and 13.

[183] Response to Cities 30-1 in Docket No. 34800. 106 Q. PLEASE DISCUSS YOUR FIRST ADJUSTMENT RELATING TO THE 1997 ICE STORM. A. Included in the insurance reserve is a charge of $13,014,379 associated with the January 13, 1997 ice storm.

[184] This particular storm resulted in a separate docket before the Commission in which the Company's actions were investigated. That proceeding was Docket No. 18249. The Order on Rehearing identified the following critical issues or problems associated with the Company's actions that led, in part, to the significant cost associated with storm restoration efforts: • The Company conceded that it did not have a traditional pole inspection program. With the Entergy-GSU merger, the Company reduced the number of inspections for poles. The Company's pole inspection and work cycles were not sufficiently rigorous, continuous or frequent to maintain all of its facilities in the condition required to meet its reliability and service obligations under PURA.

[185]

[184] Response to Rose City 5-2.

[185] Docket No. 18249 Order on Rehearing page 9.

[186] Id., at pages 9 and 10.

[187] Id., at page 15.

[188] Id. 107 1 deploy non-EGS personnel were slow and caused concern, vegetation management failures greatly aggravated the situation." 189 2 3 • The Company's management structure is ill-suited to assure best supervision of the T&D System in the Texas territory. 190 4 5 • The inspection program carried out by the Company was not sufficiently 6 extensive or adequate to fulfill its proposed purpose of securing reliable service. 191 7 8 • The Company's distribution system maintenance practices fail to assure continuance and adequate service to customers. 192 9 10 • "Negligent and backlog of vegetation management projects has posed 11 unacceptable risk of increasing and recurrent service outages, especially during major storms." 193 12 13 14 Moreover, the Proposal for Decision in Docket No. 16705 stated the following regarding 15 the 1997 ice storm: 16 17 First, the ALJs recommend the Commission ignore the $13 million in this 18 case. EGS did not meet its burden to prove that the $13 million 19 expenditure was prudent and reasonable, or even that it was necessary.

[189] Id., at pages 17-18.

[190] Id., at FOF 26.

[191] Id., at FOF 45.

[192] Id., at FOF 46.

[193] Id., at FOF 82.

[194] Docket No. 16705 PFD at page 186. 108 the Commission exclude the $13 million of ice storm related charges from the 2 Company's insurance reserve. 3 4 Q. PLEASE DISCUSS YOUR SECOND ADJUSTMENT TO THE COMP ANY'S INSURANCE RESERVE ASSOCIATED WITH DEDUCTIBLE LEVELS. 5 The Company's self-insurance program fails to comply with standard insurance practices 6 A. 7 and in fact, creates a perverse incentive. The issue is the Company's failure to treat the 8 lower $50,000 threshold as a deductible event. Indeed, with normal insurance policies, an 9 incentive is provided to the party purchasing insurance to not make unreasonable or 10 frivolous claims. Part of that deterrent is the requirement of a deductible. In this case, the 11 $50,000 minimum threshold employed by the Company should serve the purpose of 12 being the deductible in the insurance process.

[195] Response to Rose City 5-1, including the ice storm.

[196] P.U.C. Subst. Rule 25.23 l(b)(l)(G).

[197] Response to Rose City 20-6 and Response to Cities 30-4 in Docket No. 34800. 110 Q. CAN THE COMPANY PROVIDE ANY DOCUMENTATION OR SUPPORT FOR ITS INCLUSION OF HARDWARE ACQUISITION IN THE PROPERTY INSURANCE RESERVE? No. The Company was specifically requested to explain in detail and justify the inclusion A. of costs associated with computer hardware acquisitions into the property insurance reserve. The Company's entire response to the request for "all support" was that ''these charges were related to and deemed necessary for storm restoration." 198 (Emphasis added). The word "deemed" does not rise to the level of credible support for the inclusion of computer hardware costs into the storm reserve. Q. DO EXPENDITURES FOR FIRE AND PROPERTY INSURANCE PREMIUMS QUALIFY FOR STORM INSURANCE RESERVE TREATMENT? A. No. There is no credible claim that premiums for fire and property insurance are not

[198] Response to Rose City 21-33.

[199] Response to Rose City 21-22.

[200] Response to Rose City 5-1 Attachment 1, footnote 2. 111 I 1 shift $12,498,325 of charges previously recorded as Louisiana costs to the Texas jurisdiction.

[201] 2 3 4 Q. HAS THE COMPANY DEMONSTRATED THAT ITS PROPOSED ADJUSTMENT IS APPROPRIATE? 5 No. In fact, the Company's presentation is an after the fact attempt to change the 6 A. 7 historical allocation process. 8 9 Q. HAS THE COMMISSION PREVIOUSLY RECOGNIZED POTENTIAL 10 PROBLEMS WITH THE COMPANY'S AFTER THE FACT POLICY CHANGES 11 AS IT RELATES TO ALLOCATION OF COSTS BETWEEN JURISDICTIONS? Yes. In Docket No. 34800, the Commission stated the change in the way that the 12 A. Company allocated its transmission costs is "a policy decision that should be made by the 13

[204] Response to Rose City 23-21. 20s Id.

[206] Testimony of Mr. Wright at page 20. 113 1 Q. WHAT DO YOU RECOMMEND? 2 A. I recommend that the storm reserve deficit balance be adjusted upward (less negative) by $1,518,978 to reflect the additional funds received, or increased estimates by the 3 4 Company, for insurance proceeds relating to Hurricanes Katrina and Rita and by 5 $3,791,732 for reversal ofETI proposed Adjustment 15. 6 7 Q. WHAT IS THE IMP ACT OF YOUR VARIOUS RECOMMENDATIONS TO THE 8 COMPANY'S CLAIMED CURRENT LEVEL OF STORM RESERVE 9 DEFICIENCY? 10 A. The Company claims a $64,355,152 current deficiency in its storm insurance reserve. 11 The adjustments previously discussed total $16,857,757, and reduce the Company's 12 claimed storm insurance reserve deficit to a deficit of $47,497,395.

[207] Direct Testimony of Mr. Wilson page 9 of 18 in Docket No. 34800, but included the anticipated impact of major hurricanes. 114 I l claims that in any 25-year period, the largest annual expected stonn loss totaling less than a$100 million is approximately $19.3 million. 208 2 3 4 Q. DID MR. WILSON RELY ON THE MONTE CARLO ANALYSIS FOR THE 5 ESTABLISHMENT FOR THE TARGET RESERVE LEVEL IN THE LAST 6 CASE? No. Mr. Wilson admitted that he did not use a Monte Carlo analysis in the last 7 A. proceeding. 209 8 9 DOES MR. WILSON'S MONTE CARLO SIMULATION INCLUDE THE 10 Q. IMPACT OF THE PREVIOUSLY DISCUSSED 1997 ICE STORM? 11 Yes.210 12 A.

[208] Direct Testimony of Mr. Wilson at page 10.

[209] Deposition of Mr. Wilson on April 22, 2010 at TR 30.

[210] Id., at TR 28.

[211] Response to OPC 2~ 1 O(b ). 115 1 Q. DID MR. WILSON NORMALIZE ms DATABASE PRIOR TO PERFORMING 2 THE MONTE CARLO SIMULATION? 3 A. No. While Mr. Wilson trended his historical loss data based on inflation considerations, 4 he failed to nonnalize for any other factors. Other factors include items such as 5 vegetation maintenance that the Company implemented after the 1997 ice stonn. any 6 process improvements developed as part of planning for stonn recovery activities, better 7 software mapping systems of the Company's service territory or other factors that would 8 change the resulting costs if the same stonn were to occur in the future. 9 10 Q. IN YOUR OPINION, IS THE msTORICAL DATABASE ARTIFICIALLY SKEWED TO PRODUCE IDGH..SIDE COST ESTIMATES? 11 Yes. Mr. Wilson's sole efforts associated with attempting to recognize inflation and 12 A.

[212] Direct Testimony of Mr. Wilson at page 7. zu Id. m Direct Testimony of Mr. Wilson in Docket No. 34800 at page 5.

[215] Mr. Wi1son•s Direct Testimony at page 7. 117 1 Q. HAVE YOU REVIEWED MR. WILSON'S MONTE CARLO SIMULATION, WIDCll FORMS THE BASIS FOR ms PROPOSAL? 2 3 A. Yes. As previously discussed, the Monte Carlo simulation is a new process employed by Mr. Wilson. As previously noted, the database relied upon for simulation purposes 4 5 includes many significant levels of cost that are inappropriate for ratemaking purposes 6 and for purposes of predicting reasonable future expectations. In addition, the Company's 7 analysis fails to recognize any factor other than inflation that can and will impact the 8 severity of costs incurred in future storms. In addition, Mr. Wilson,s simulation over 9 estimates the number of storms eligible for inclusion in the stonn reserve, thereby 10 increasing the projected annual total of stonn related O&M expense of reach of his 5,000 11 iterations in his Monte Carlo simulation. 12

[216] Docket No. 35717 Final Order at FOF 100 and page 111 of the Proposal for Decision. 118 greater than the next highest value reported in the Company's database, that being 1997. As previously noted, the 1997 value includes over $13 million associated with the most severe ice stonn the Company has ever experienced and which reflects excessive cost levels due to inappropriate actions by the Company. Removing the 1997 storm-related activity renders the 2007 Humberto related value at over 1500/o greater than the next highest value reflected in the Company's 20 plus year historical database. Therefore, reliance on a I 0-year historical period only serves to artificially inflate the expected annual storm loss level. Q. HA VE YOU ANALYZED THE HISTORICAL DATA FROM THE STANDPOINT OF ESTABLISIDNG A REASONABLE ANNUAL STORM LOSS? 12 A. Yes. Review of the historical data, even on a trended loss basis, but absent the impact of

[217] The JO-year average trended loss value is $3.8 million. while the 20-year avenge is $3.6 million. 119 1 through base rates for the insurance reserve annual stonn amounts. Therefore, the higher the annual storm reserve amount set, the greater amount the Company actually recovers 2 3 from customers over time, but for which it does not credit customers. Such amounts become additional return for the Company, rather than a credit to the insurance reserve. 4 5 6 Q. WHAT DO YOU RECOMMEND? 7 A. Based on the approaches discussed above, I recommend retention of the recently adopted $3,651,320 annual stonn loss value. This results in a $1,618,680 reduction to the 8 Company's request. 9 Minimum Storm Reserve Threshold IO 5. 11

[218] Response to Rose City 9-2.

[219] Response to Rose City 9-3.

[220] Id. 120 1 Q. HAS TIIE COMPANY COMPARED ITS SS0,000 MINIMUM THRESHOLD TO 2 ANY OTHER UTILITIES FOR PURPOSES OF DETERMINING 3 REASONABLENESS? 4 A. No. The Company states that it "has not compared its stonn ~rve policies with any other utility."22 1 5 6 7 Q. IS THE SS0,000 MINIMUM TIIRESHOLD REASONABLE? 8 A. No. The Company has incurred 155 stonns that it claims qualify for stonn reserve treatment subsequent to Docket No. 16705. 222 This represents in excess of 10 storms per 9 year, not counting Hurricane Rita and Hurricane Ike. Occurrences of this frequency on an 10 11 annual basis cannot credibly be claimed to comply with the Commission's rules that are

[221] Id.

[222] Response to Rose City 5-1.

[221] P.U.C. Subst Rule 25.23 l(bXl)(G}. :m Mr. Wilson's deposition on April 22, 2010 at TR 11. 121 1 Q. HAS THE COMMISSION RECENTLY RULED ON THE ISSUE OF WHAT 2 CONSTITUTES A REASONABLE MINIMUM INSURANCE THRESHOLD 3 DEDUCTmLE LEVEL? 4 A. Yes. In Docket No. 35717, an Oncor Delivery case, the issue as to whether to increase the minimum threshold level to $10 million was raised. Oncor's witness stated that the 5 6 "demarcation point at $500,000 is the hallmark in risk management because losses under $500,000 are considered routine and predictable. Anything over that loss cannot be 7 predicted." 225 The Commission in Docket No. 35717 accepted the $500,000 minimum 8 threshold for storm reserve treatment.

[226] 9 10 11 Q. WHAT DO YOU RECOMMEND? 12 A. I recommend increasing the minimum threshold level from $50,000 per storm to

[225] Docket No. 35717 Proposal for Decision at page 106.

[226] Docket No. 357 J 7 Final Order FOFs 98-101. 122 1 SECTION VI: CASH WORKING CAPITAL 2 1. Introduction 3 WHAT IS THE ISSUE IN nus PORTION OF YOUR TESTIMONY? 4 Q. This portion of my testimony deals with ewe. ewe is a component of rate base and 5 A. represents the amount of funds supplied by either the shareholders or others, such as 6 7 customers, to fund the day-to-day operations of the Company. 8 9 Q. HOW DID THE COMPANY ARRIVE AT ITS PROPOSED CWC? The Company has attempted to perform a lead-lag study in its efforts to quantify its CWC 10 A. requirements. The type of study is a cash lead-lag study as required by P.U.C. Subst. R. 11

[227] Schedule E-4 page 2.

[228] Response to State of Texas 8-9.

[229] Docket No. 16705 Final Order Schedules lV and Vl. 123 Q. PLEASE SUMMARIZE YOUR RECOMMENDATIONS IN TIUS PROCEEDING l AS IT RELATES TO YOUR REVIEW OF THE COMPANY'S ewe REQUEST. A. The Company's negative ewe estimate is again substantially inadequate {i.e. too little level of negative CWe). A more appropriate level ofCWC is a negative $45.7 million or $43. 7 million more negative than the Company's original request as set forth on Schedule {JP-4). While, again in this case, there are many problems associated with the Company's lead-lag study, I have attempted to correct mainly the major components and make adjustments to comport with Commission precedent A summary of the specific areas and issues follows. • Meter· To-Billing Revenue Lag. In spite of expenditures for electronic meter reading equipment, new computer hardware and software, the Company proposes

[230] The revenue lag represents the claimed time period between date(s) the Company provides service to I customers and the date(s) the Company receives funds from the customer for such service. An expense lead is the time period between the date(s) the Company receives a product or service and the date(s) it pays for such product or service.

[231] Direct Testimony of Mr. Gallagher at page 8. I 126 1 Mr. Gallagher's discussion of service period between expenses and revenues violates 2 prior Commission decisions as well as logic and consistency. In particular, Mr. 3 Gallagher would have the Commission believe that it is logical and consistent to measure 4 the revenue lag as the time period during which customers receive service. For example, 5 if a customer's meter readings occur on April and May 1st, the service period is one 6 month or 30 days. On average, the customer will have received the service 15 days into 7 the 30-day period. This concept of service period has nothing to do with the fact that the 8 recording of the actual revenues that will be charged to the customer do not occur until later in May when the billing process is completed. Alternatively, Mr. Gallagher would 9 10 have the Commission believe that the service period associated with expenses occurs

[232] Company Work.paper WP/E-4 page 3. 127 1 recognizable benefits for customers given that customers must pay a return of and a 2 return on such investments. Unfortunately in this area, the Company has become less 3 efficient in the billing process in spite of such substantial capital expenditures. 4 5 Q. HAVE OTHER REGULATORY BODIES RECOGNIZED THE MORE 6 EFFICIENT BILLING PROCESS ASSOCIATED WITH MORE MODERN 7 ELECTRONIC METER READING DEVICES AND BILLING SYSTEMS? 8 A. Yes. The Railroad Commission of Texas ("RCT'). the regulator of gas utilities in Texas, has adopted a I -day meter reading to billing lag for the largest gas utility in the state. 233 9 10 Moreover, the RCT adopted such shorter period of time in spite of the gas utility's

[233] RCT GUD 9869, Atmos Gas Company.

[234] RCT GUD No. 9670 Final Order FOF 126, and GUD No. 9902.

[235] RCT GUD No. 9670 Final Order at FOF 148.

[236] Company Workpaper WP/E-4 page 26 of 47 in Docket No. 12852 also set forth as Exhibit (JP-16) in Mr. Pous' Testimony in Docket No. 16705. 128 1 Q. WHEN YOU STATE THAT THE METER READING-TO-BILLING PERIOD 2 HAS INCREASED RATHER THAN DECREASED, ARE YOU JUST 3 REFERRING TO THE 1.46 DAY PERIOD PREVIOUSLY REFERENCED? No. While it obviously has increased from Docket No. 12852, it has also increased from 4 A. 5 Docket No. 16705 where the Company proposed a 3.61-day meter reading-to-billing lag. 6 It is apparent that the Company, absent proper direction from this Commission to 7 demonstrate that it will not tolerate inefficiencies in the billing process, will have a 8 perverse incentive to perfonn in a manner that is detrimental to customers. In fact, the 9 Company has every incentive to be inefficient in this particular area because it earns a

[237] Schedule E-4 page 2 of 2 average daily amount of $4,324,957 times l .15 days (3 .63-1.46) X .528732.

[238] Company Workpaper WP/E-4 page 3.

[239] Company Workpaper WP/E-4 page 3.

[240] Id, at page 17. 130 1 receivable balance and compares that to the average daily revenues. The problem with 2 this approach rests on the premise that the end of month accounts receivable balance is 3 equivalent to the individual daily accounts receivable balances throughout the month. 4 Given that the Company has 21 different billing cycles throughout the month, the 5 accounts receivable monthly ending balance is skewed towards customers billed in the 6 later billing cycles and does not reflect the relationship experienced by those customers 7 billed in the early billing cycles of the month who have already paid their bill and are no

[241] Docket No. 30123 Company Workpaper WP/E-4 page 2.

[242] Docket No. 12852 Company Workpaper WP/E-4 page 26 of 47.

[243] Workpaper WP/1-A-1-111.1 AJ12-1 in Volume 40-VL at page 838 in Docket No. 22356 and Workpaper WP/E-4 page 4 in Docket No 34800. 131 1 Q. DID YOU SEEK INFORMATION NECESSARY TO QUANTIFY A MORE 2 ACCURATE BILLING-TO-COLLECTION REVENUE LAG FOR THE 3 COMP ANY IN THIS CASE? 4 A. Yes. I sought the Company's daily accounts receivable balances for retail sales, the aging of accounts receivable reports for each month of the test year, and the daily revenue 5 receipts during the test year. The Company does not maintain all such information. 244 6 7

[244] Response to Cities 9-18.

[245] Response to Cities 9-6. 132 1 Q. GIVEN THE CIRCUMSTANCES THE COMPANY HAS PRESENTED, WHAT 2 DO YOU RECOMMEND? 3 A. The Company's current request is obviously incorrect and cannot be relied upon. 4 Unfortunately, the Company was unable to provide necessary information associated 5 with the current test year as it pertains to daily accounts receivable balances or even daily 6 revenues. Therefore, I recommend a modified aging of accounts receivable approach

[246] Docket No. 16705 Company response to Cities 97 - 1 as shown on Schedule (JP-17) in that case.

[247] PUC Subst. R. 25.28.

[248] Docket No. 16705, PFD at Section F 2 (a).

[249] Id. 133 l Q. DO YOU BELIEVE TIDS APPROACH IS MORE REPRESENTATIVE THAN 2 THE COMP ANY'S PRESENTATION? 3 A. Yes, and for the various reasons noted above, the Company's position is in error. The 4 Company's position is not only excessive but unsupportable. The Company has elected 5 not to maintain the type of data that would permit a more accurate current calculation.

[250] Total revenue lag days decline to 39.84 ifMSS-4 revenues are removed. This represents a 3.33 reduction in revenue lag days from ETI's proposed level of 43.17 days (3.33 x $4,324,957 = $14,408,915).

[251] Company Workpaper WP/E-4 page 3.

[252] Mr. Gallagher's Direct Testimony at page 13.

[253] Company Workpaper WP/E-4 pages 14-16.

[254] Company Workpaper WP/E-4 page 7. 135 I 1 transfer or other electronic manners.

[255] Recognition of cash and electronic payments by 1 2 dollar amount rather than by count reduces the 0.95 check float to 0.49. I 3 4 Q. WHAT DO YOU RECOMMEND? I 5 A. I recommend the Company's request for a 0.95-day customer float be denied. The

[255] Response to Rose City 9-12.

[256] Company Work.paper WP/E-4 page 2. 136 1 Q. IS THE COMPANY'S PROPOSED PAYROLL EXPENSE LEAD DAYS IN 2 COMPLIANCE WITH THE COMMISSION'S ORDER IN DOCKET NO. 16705? No. In Docket No. 16705 at FOP 114, the Commission adopted the position I sponsored 3 A. 4 in that case. In doing so the Commission stated that "recognizing vacation time as a

[257] Company Workpaper WP/E-4 page 164.

[258] Response to Rose City 9-1 6 . 137 1 Q. HOW DID YOU ADJUST THE COMPANY'S PROPOSED PAYROLL EXPENSE 2 .LEAD DAYS FOR THE PROPER RECOGNITION OF VACATION PAY? I began with the Company's payroll of $35,210,377.

[259] I then subtracted the test year 3 A. vacation pay amount of $3,842,535.

[260] Next, I applied a 210.67 lead day period to 4

[259] Company Work.paper WP/E-4 page 294.

[260] Response to Rose City 9-16.

[261] Response to Rose City 7-l(E).

[262] Company Work.paper WP/E page 164. 138 IS THERE ANY REASON NOT TO RECOGNIZE THE MARCH 12 111 OF THE 1 Q. 2 FOLLOWING YEAR AS THE APPROPRIATE DEFERRED PAYMENT DATE? No. The Company's action is based on the same illogical and inconsistent opinion of Mr. 3 A. 4 Gallagher that assumes that the service period for expenses begins when an expense is

[263] Response to Rose City 7-l(E) ..

[264] Direct Testimony of Mr. Gallagher at page 18.

[265] Response to Rose City 24-55. 139 1 2 Q. IS THE ELIMINATION OF FAS 106 IN COMPLIANCE WITH THE 3 PRECEDENT SET IN THE COMPANY'S LAST FULLY LITIGATED RATE 4 CASE?

[266] Schedule (JP-15) page 2 of2 in Docket No. 16705. 140 1 Q. WHAT IS THE IMP ACT OF YOUR RECOMMENDATION? 2 A. Given that the Company has proposed $2,522,308 of FAS 106 expense for the test year, 3 in conjunction with the 312.55 expense lead days I am recommending, results in a

[267] Response to Rose City 24-55. ' r

[268] Company Workpaper WP/E-4 page 2.

[269] Company Workpaper WP/E-4 page 764.

[270] Response to Rose City 6-4 through 6-10. 141 Therefore, an incremental 241.5 days must be recognized for the incentive compensation 1 2 portion of the ESI charges. 3

[271] Company Workpaper WP/E-4 page 2.

[272] Id., in Docket No. 34800.

[273] Testimony of Mr. Gallagher at page 19. 142 1 Q. HAVE YOU REVIEWED THE SAMPLE AND THE COMPANY'S PROPOSED 2 RESULTS FROM SUCH SAMPLE? 3 Yes. As was the situation in prior cases, the Company has made several errors in A.

[274] Company Workpaper WP/E-4 pages 828 and 878-880.

[275] $126,190 x .993/$2,599,973.62 x 30 days= 1.45 days. 143 1 invoice caused the Other O&M category lead days to be understated by 0.47 days (l.45 x 2 0.3259). A loss of 0.47 lead days for this Other O&M category that has a $233,838 3 average daily balance increases rate base by $109,904 ($233,838 x 0.47). Using a 12%

[276] Company Workpaper WP/E-4 page 1026.

[277] Id., at page 972 for sample number 13. 144 1 Q. WHY DO YOU STATE THAT THE COMMISSION MAY NOT HAVE 2 AUTHORITY TO RULE ON DECOMMISSIONING REVENUE

[278] Direct Testimony of Mr. Gillam at page 3.

[279] Gillam Exhibit PEG-3. 145 1 received 20-year license extensions for nuclear units and is in the process of seeking 20- 2 year license extensions for several other nuclear generating facilities. In addition, the

[280] Direct Testimony of Mr. Gillam at pages 4-6, and Exhibit PBG-3 . 146

[281] Id., at Exhibit PBG-3.

[282] Response to Rose City 10-3.

[283] Response to Rose City 10-3 and 10-2. 147 1 Q.

[284] Deposition of Mr. Caruso on April 29, 2010 at TR 54.

[28] s Entergy Corporation August 13, 2009 letter to the NRC regarding the "Decommissioning Funding Assurance Plans." 148