Loading...
HomeMy WebLinkAboutMotion to Intervene -2 - §§ 385.211, 385.212 and 385.214, the Truckee Donner Public Utility District("Truckee") moves to intervene in this proceeding and protests Sierra's filing. I. MOTION TO INTERVENE A. Truckee's Interest in the Proceeding Truckee is a public utility district of the state of California engaged in the distribution, sale and delivery of electric power and energy. Truckee serves more than 13,000 electric customers, with a peak load of approximately 35 MW. Truckee is a non- profit entity, whose purpose is to provide economical, reliable retail electric service to its customers, the citizens and businesses in and around the town of Truckee, California, located high on the eastern slope of the Sierra Nevada. Truckee is a transmission- dependent utility located within the control area of Sierra Pacific Power Company, and is not interconnected with any other utility. Truckee is a network transmission service customer under Sierra's joint GATT. Truckee uses this network service to import into and transport across Sierra's grid all of the power necessary to serve Truckee's load, and thus will be affected by Sierra's filing. Truckee's intervention is therefore in the public interest and should be granted. B. Communications The names, addresses and telephone numbers of the persons to whom communications concerning this matter should be addressed are as follows: - 3 - Mr. Stephen A. Hollabaugh Margaret A. McGoldrick TRUCKEE DONNER PUBLIC UTILITY Jeffrey A. Schwarz DISTRICT SPIEGEL&MCDIARMID LLP Post Office Box 309 1333 New Hampshire Avenue,N.W. Truckee, California 96160 Washington, D.C. 20036 (530) 587-3896 (202) 879-4000 (530) 587-5056 (fax) (202) 393-2866 (fax) Email: stenhenhollabaugh& dpud org Email: margaret.mcgoldrick@spiegelmcd.com jeffrey.schwarz(a)spiegehncd com II. PROTEST A. Sierra Has Not Shown that the Use of Stated Rates for Network Transmission Service Is Just and Reasonable Absent Periodic Updating of the Billing Determinants 1. Sierra Bears the Burden of Proving that Its Proposed Rate Design Is Just and Reasonable and Cannot Rely on a Non- Precedential Settlement to Shift the Burden Until May 2005, Sierra calculated its Zone A network transmission service charges—consistent with the Commission's pro forma open access transmission tariff ("OATT")—on a monthly load-ratio share basis. Network transmission customer charges automatically reflected changes in total monthly billing determinants. In its October 2004 filing in Docket No. ER05-14-000, however, Sierra proposed to replace that long-established rate design with stated rates for network transmission service.3 Truckee (and others) protested Sierra's change to stated rates for network service, explaining that the shift would deprive Sierra's network customers of the benefit of load growth and would cause Sierra to over-recover its revenue requirement.4 3 Sierra Pac. Res. Operating Cos., 109 F.E.R.C. 161,245, P 3 (2004), clarified, 110 F.E.R.C. 161,126 (2005). 4 Motion to Intervene,Protest, and Request for Suspension and Hearing of Truckee Donner Public Utility District,Sierra Pac.Res. Operating Cos.,Docket No.ER05-14-000,4-11 (Oct.22,2004)("Truckee ER05- 14 Protest"),available at eLibrary Accession No.20041022-5079. -4 - The Commission suspended Sierra's proposed rates for five months, allowing them to become effective subject to refund on May 1, 2005, and established hearing and settlement procedures. 109 F.E.R.C. ¶61,245 at P 1. The Commission declined to reject summarily Sierra's proposed shift to stated rates for network transmission or to require summarily that Sierra's rates be updated periodically to reflect changes in the total billing determinants. Id. at P 9. However, as it explained on clarification of its initial order, the Commission set for hearing and settlement discussions "whether updating or any other modifications of the stated network rate design are needed." 110 F.E.R.C. ¶61,126 at P 8. Ultimately, the SPR Operating Companies, Truckee, the City of Fallon, Nevada, Newmont Mining Corporation, and Barrick Goldstrike Mines, Inc., reached a settlement, which the SPR Operating Companies filed on March 8, 2005, with a proposed effective date of May 1, 2005. In effect, the settlement deferred debate about whether Sierra's network transmission rate design had been shown to be just and reasonable under FPA Section 205. It did so by establishing negotiated stated rates for Network Integration Transmission Service in Zone A that would be implemented without updating (and without precedential effect) for a limited period of time. Essentially, the parties agreed that a first update would occur no later than September 15, 2007, and lef the question of subsequent updates open, to be resolved in a future proceeding. As the SPR Operating Companies stated in the Explanatory Statement accompanying the Settlement Agreement (at 4, emphasis added): The issues in this case are (1) the appropriate rate level for service on Sierra Pacific Power Company's transmission system, and (2) whether SPR's stated rate should be updated periodically. The Settlement avoids resolution of - 5 - those issues through agreement on a "black box"rate level and a required Section 205 filing by September 15, 2007.151 There are no major implications of this Settlement. The Parties have agreed that the Settlement will have no precedential effect. Section 6 of the Settlement Agreement contained not only the common boilerplate language explaining that the agreement shall not constitute any precedent or admission that may be applied against any Party for any purpose, and no Party shall be deemed to have approved, accepted, agreed, or consented to any fact, concept, theory, principle, or method related to the justness or reasonableness of any matter, premise or issue in this proceeding. Settlement Agreement § 6. It went further and addressed the rate design issue specifically, providing that: In particular, the Parties agree that the fact that they have agreed to a fixed demand charge for Zone A Network integration Service set forth in Attachment H to the SPR OATT shall not be used as precedent with respect to the issue of whether or how such demand charge should be subject to periodic updating, and SPR shall not make any argument in any future proceeding that such issue is foreclosed or has been waived by any of the other Parties by virtue of their having entered into this Agreement. Id., emphasis added. Commission Trial Staff s comments in support of the settlement noted both the disclaimer of precedential effect as to the"stated rate issue"and the requirement that SPR Operating Companies initiate a new Section 205 proceeding to provide cost support for 5 Specifically, Section 2(a) of the Settlement Agreement required the SPR Operating Companies to "initiate a proceeding pursuant to Section 205 of the Federal Power Act on or before September 15,2007, to provide cost support pursuant to 18 C.F.R. § 35.13(a)for the existing or new base transmission service rates of Sierra Pacific Power Company." The settlement further provided that "[t]he Parties make no commitments with respect to the contents of that filing or the relief requested therein." Id. - 6 - Sierra's existing or new base tariff rates by September 15, 2007.E No other comments were received and the settlement judge certified the settlement to the Commission as uncontested. The order approving the settlement noted that "approval of this settlement does not constitute approval of, or precedent regarding, any principle or issue in this proceeding." 111 F.E.R.C.¶61,173 at P 3. As the SPR Operating Companies explained, the Docket No. ER05-14-000 settlement was intended to "avoid[] resolution of the issues raised by the Companies' Section 205 filing initiating that docket. Settlement Agreement Explanatory Statement at 4. The Docket No. ER05-14-000 settlement deferred the question whether Sierra's proposed use of stated rates for network transmission service, without periodic updating, is just and reasonable under Section 205. However, the deferral was temporary. The settlement required the SPR Operating Companies to make a new Section 205 filing in September 2007, which, assuming that Sierra continued to propose the use of stated rates without updating, would present the question anew and without a bias resulting from the settlement's temporary acceptance of that rate design. The instant Section 205 filing continues to propose the use of stated rates for network transmission service, without updating to reflect changes in total billing determinants, and therefore raises the question that the Docket No. ER05-14-000 settlement deferred. As the proponent of this proposed rate design, SPR Operating Companies bear the burden of demonstrating that the use of stated rates for network 6 See Initial Comments of the Commission Trial Staff in Support of Offer of Settlement,Sierra Pac. Res. Operating Cos., Docket No. ER05-14-000, 7-8, 10 (Mar. 15, 2005), available at eLibary Accession No. 20050315-5022. See Sierra Pac. Res. Operating Cos., I I I F.E.R.C.¶61,173,P 1 (2005). - 7 - transmission service, without updating, is just and reasonable. For the reasons set forth below, they have failed to make that showing. Indeed, perhaps hoping that the settlement's temporary acceptance of such rates would shift the burden to intervenors to attack that rate design, SPR Operating Companies failed to include in this filing any support for the use of stated rates for network transmission service, rather than the long- established rate design, based on load-ratio shares, that was in place prior to the settlement in Docket No. ER05-14-000. 2. The Use of Stated Rates for Network Integration Transmission Service, Without Updating, is Not Just and Reasonable The Commission should reject the SPR Operating Companies' proposed use of stated rates for network transmission service both because of the absence of support for that rate design in the Companies' Section 205 filing and for the reasons that Truckee expressed in its Docket No. ER05-14-000 pleadings. In that proceeding, SPR Operating Companies proffered a number of specious justifications for the proposed change in the Zone A rate design.8 Truckee need not repeat here its refutation of those attempted 8 For example, SPR Operating Companies claimed that charging stated rates for network transmission in Zone A was necessary to preserve consistency with the rate design in Zone B. However, as Truckee explained, the adoption by settlement of stated rates for network transmission in Zone B expressly stated that it was not to "constitute any precedent or admission that may be applied against any Party for any purpose,including but not limited to ... any determination regarding the transmission rates of Sierra Pacific Power Company." See Truckee ER05-14 Protest at 4-5 &n.4(quoting Settlement Agreement,Sierra Pac. Res. Operating Cos., Docket No. ER03-1328 (May 17, 2004), available at eLibrary Accession No. 20040518-0139, and approved by Sierra Pac. Res. Operating Cos., 108 F.E.R.C. 161,023(2004)). Truckee further explained that, if the SPR Operating Companies truly desired ratemaking consistency between Zones A and B, the Companies should file a single blended rate for service throughout their combined transmission systems. Id. at 5-6. Truckee also refuted the implication that needs for predictability and simplicity justified the switch to stated rates for Zone A network transmission service, pointing out that Sierra has very few network transmission customers and very few retail customers eligible under state law to switch providers. Id. at 4,6-7&n.9. Finally, Truckee distinguished the cases cited by the SPR Operating Companies in answer to its protest,Reply of Truckee Donner Public Utility District to Answer of Sierra Pacific Resources Operating Companies,Sierra Pacific Resources Operating Companies, Docket No. ER05-14-000, 4-6 (Nov. 19, 2004) available at eLibrary Accession No. 2004 1 1 1 9-503 0, - 8 - justifications because SPR Operating Companies have not advanced them—or any other attempted justification —in support of their proposed use of stated rates for network transmission in this case. In Docket No. ER05-14-000, Truckee also explained that any switch to stated rates for network transmission service must be implemented (if at all) in a manner that allows network transmission customers to benefit from load growth. Truckee ER05-14 Protest at 9-11. Absent updating to reflect load growth, the use of stated rates for network transmission service will result in predictable but unjustified de facto rate increases and over-recovery of Sierra's revenue requirement. The use of stated rates for network transmission service raises to critical importance the accuracy of the load projections used as the denominator in the unit-rate calculations. If projected loads are too low, the resulting rates will be too high—even at the outset. As discussed in Part B.1 below, Sierra's proposed unit rate in this case is excessive because it is based upon understated load projections. More to the point, even if Sierra's Period II load projection were reasonable, load growth over time would cause Sierra to collect ever increasing amounts from its network transmission customers, without any filing and without justification. Sierra's proposed use of stated rates and its predictable over-recovery over time are inconsistent with the Commission's pro forma tariff, which provides that customers' network transmission charges are automatically reduced whenever new load is served under the OATT.9 But the SPR Operating Companies have not shown that the use of stated rates for network transmission service in although the Commission declined to accept either the SPR Operating Companies' answer or Truckee's reply, 109 F.E.R.C.¶61,245 at P 6. 9 Notably, the pro forma tariff approach also protects the Company against the unlikely event of load shrinkage. - 9 - Zone A is consistent with or superior to the pro forma tariff approach. The Commission should therefore reject it. Alternatively, and at a minimum, the Commission must follow the course it charted in Docket No. ER05-14-000 and set for hearing whether Sierra's proposed stated rates are just and reasonable or whether "updating or any other modifications" are required. See 110 F.E.R.C. ¶ 61,126 at P 8.10 In doing so, it should make clear that SPR Operating Companies bear the burden of demonstrating that Sierra's proposed rate design, which the Commission has not accepted outside the context of a non-precedential settlement, is just and reasonable. B. Sierra's Existing Zone A Rates Are Already Overstated, and the Proposed Rate Increase Is Wholly Unjustified The SPR Operating Companies propose to increase the Zone A transmission rate from $2.88/kW-month to $2.97/kW-month, an increase of $0.09/kW-month or 3.1%. The Companies suggest that the major factor driving the proposed rate increase, based upon projected 2008 costs, is plant additions on the Sierra transmission system (Exhibit SPR-1 4:13-20). However, the projected gross plant increase from $565.7 million in 2006 to $601.1 million in 2008 (id.), an increase of$35.4 million, is substantially offset by an additional two years' of accumulated depreciation totaling $21.2 million (based on plant in-service during 2006). Further, as discussed below, it may be that some of the transmission facilities recently added are interconnection facilities that should be directly 10 We note that there are substantive links between Sierra's proposed rate design and its proper cost of service—particularly, the just and reasonable level of return on equity. Given the likelihood that use of stated rates without updating for load growth would produce increasing transmission revenues,the adoption of such a rate design would decrease the riskiness of investment in Sierra and would reduce the just and reasonable level of return on equity. - 10 - assigned rather than added to the transmission rate base. The SPR Operating Companies' reference to recent transmission additions fails to explain, much less justify, the proposed rate increase. Indeed, the primary driving factor appears to be an unexplained and unjustified reduction in projected revenue credits.l� Truckee's preliminary analysis of Sierra's cost-of-service data shows that the existing Zone A rate of$2.88/kW-month is excessive, thus amplifying Truckee's concern that the use of a stated network rate without some form of periodic updating will result in Sierra's over-recovery of its costs. As demonstrated in Part C. below, based on its analysis to date of the information provided with the filing, Truckee believes that the just and reasonable Zone A rate should not exceed$2.66/kW-month.12 Accordingly, the entirety of the proposed rate increase is excessive, and the Commission should therefore suspend the proposed new rate of$2.97/kW-month for the maximum five-month period. Further, because the just and reasonable transmission rate should be lower than both the last clean rate and the proposed rate, the Commission should institute an investigation under Section 206 of the Federal Power Act, and " Sierra's claimed transmission revenue requirement for 2008 is $0.897 million(or 1.6%)greater than its revenue requirement based on 2006 costs. Compare Exhibit SPR-21, Statement BK, Schedule 1, 1:23 (proposed 2008 revenue requirement of$58.567 million)with Exhibit SPR-20, Statement BK, Schedule 1, 1:23 (claimed transmission revenue requirement based upon 2006 costs of $57.670 million). The preponderance of this increase results from a projected decrease in transmission revenue credits from $2.596 million in 2006 (id. 22) to $1.894 million in 2008 (Exhibit SPR-21, Statement BK, Schedule 1, 1:22), a decrease of$0.702 million. As discussed below, Sierra has not justified its assumed decrease in the transmission revenues to be credited to the cost of service. SPR Operating Companies also project virtually no growth in Transmission System Load between 2006 and 2008 (compare Statements BB of Exhibits SPR-20 and SPR-21). As discussed below, this stagnant load growth assumption is unrealistic, appears to be contrary to Sierra's recent representations in other proceedings, and results in excessive unit rates. "Truckee has joined with certain other intervenors in this proceeding(the City of Fallon,Nevada, and the Newmont Mining Corporation) in engaging expert consultants to identify issues regarding Sierra's proposed rates. The conclusions reached about the overstatement of current rates as well as the unjustified nature of the proposed increase are the product of that joint effort. - 11 - establish the earliest possible refund-effective date for rate reductions that may be ordered.13 Truckee discusses below a number of deficiencies and concerns regarding Sierra's proffered cost support for its proposed rates. These issues were developed based on a preliminary review of Sierra's filing in the limited time available, and cannot be viewed as a comprehensive survey of all possible issues. Accordingly, Truckee reserves the right to raise additional issues following an opportunity for discovery and a more complete review. In addition, Truckee reserves the right to participate in full in the litigation of any issues raised by other intervenors or the Commission Staff. Further, certain of the issues discussed below—including return on equity and the understatement of the load in the rate denominator—affect not just the Zone A transmission rates,but also the proposed increase in the Schedule 1 rates. Thus, the Commission should set the Schedule 1 rates for hearing as well. 1. Period II Transmission System Load is Understated Sierra's projected Period II transmission system load appears to be understated, thereby causing the unit charges derived therefrom to be overstated. The 12-month average for the Sierra transmission system load for Period I (i.e., 2006) is 1,638 MW (Exhibit SPR-20, Statement BB). The 12-month average CP demand for Period II (i.e., 2008) is only 1,645 MW (Exhibit SPR-21, Statement BB). This near-flat projection of Sierra's total transmission system load is apparently driven by Sierra's projection of 13 See, e.g., Xcel Energy Servs., Inc., 109 F.E.R.C. 161,284, PP 20-21 (2004) (suspending proposed rate increase for five months,instituting Section 206 rate investigation and establishing refund-effective date for potential rate reduction),reh'g denied, 111 F.E.R.C.¶61,084(2005);Ameren Operating Cos.,89 F.E.R.C. ¶61,208(1999). - 12 - reduced Native Load. This projected reduction in Sierra's Native Load from Period I (1,366 MW) to Period II (1,334 MW) is atypical. It also appears to be contrary to recent claims by Sierra itself — in support of its capacity-based network service proposal in Docket No. ER07-905 — that it expects an average of 1.9% annual load growth.14 Furthermore, in that same proceeding, Sierra asserted that its "projected 2007 peak load plus reserve requirements is 1,844 MW;" this statement clearly referred to its Native Load only. If both this statement and Sierra's claim of a decline in its 12 CP load from 1,366 MW to 1,334 MW of Native Load in this case are correct, Sierra would appear to increase peak month loads and decline non-peak month loads, which seems totally incongruous. At the very least, Sierra's load projections (including its projected decline in Native Load from 2006 to 2008)must be explained and supported. The lack of any such explanation and support is all the more troubling given that the values for Sierra's Native Load for five of the 12 months in Period I shown on Statement BB are less than the actual Native Loads shown on page 401b of Sierra's 2006 FF1. The 12-month average for Sierra's Native Load for Period I based upon the 2006 FF1 is actually 1,377 MW. Had Sierra simply projected that its Native Load for Period II would be unchanged from Period I, this would have resulted in an average 12 CP Transmission System Load, after including other Network Load and long-term firm point-to-point transmission load, of 1,678 MW, using the Period I Native Load values shown in Exhibit SPR-21, Statement BB, even though some of such values do not correspond with and 14 Application of Sierra Pacific Resources Operating Companies, Docket No.ER07-905-000, 18 (May 16, 2007),available at eLibrary Accession No.20070521-0158. - 13 - may be understated relative to the 2006 FF1 values. Correcting the Transmission System Load to this 1,678 MW value would lower the indicated rate based on Period II to $2.91/kW-month($58,566,814/(1,678,000 x 12) _ $2.909). If the 2006 FF1 Native Load values were substituted for the values reported in Statement BB for Period 1, this would further reduce the indicated transmission rate to $2.89/kW-month ($58,566,814/(1,688,000 x 12) _ $2.891). It should be noted that the value of these adjustments is determined independently of the other cost-of-service adjustments described herein. As these calculations show, in a system as small as Sierra's, undercounting the load included in the denominator by as little as 40 or 50 MW would make a substantial difference in the resulting rates. The Commission must ensure that all loads are properly included in calculating Sierra's transmission rates. 2. Sierra's Proposed 11.5%Return on Equity is Excessive Sierra proposes an excessive rate of return on common equity ("ROE") of 11.5%. The proposed rate of return is much too high to constitute part of a just and reasonable transmission rate for Sierra; the overstatement of the proposed ROE warrants a full five- month suspension. While intervenors recognize the judgmental nature of the development of the investors' required rate of return, which the Commission has long held should form the basis of the ROE allowed as a cost component in wholesale electric utility rates, the Commission has provided specific guidance in recent years as to the appropriate application of the DCF model used in forming the basis of such judgment. Sierra has disregarded this guidance in developing its proposed ROE. - 14 - The proposed ROE of 11.5% is supported by the testimony of Dr. Roger A. Morin (Exhibit SPR-7) using the DCF, Capital Asset Pricing Model ("CAPM"), and risk premium methods. As will be explained below, the Commission for good reason has rejected most of the types of analyses conducted by Dr. Morin, and the DCF analyses that he does conduct, with minimal correction to conform more closely to the Commission's standard DCF methodology, support a 9.8% ROE for Sierra's level of jurisdictional transmission service risk rather than the proposed 11.5%. The ROE used in judging the reasonableness of Sierra's proposed transmission rates at this initial stage of this proceeding should be at most the median of the cost of equity results calculated for those companies in Dr. Morin's "S&P Integrated Electric Utilities" proxy group that have the same Value Line Safety Rating of 3 that Sierra Pacific Resources has, using the Commission's preferred single-stage DCF formulation as applied in the attached Appendix A. That median result is 9.8% using Dr. Morin's input data from his Exhibits SPR-13, SPR-14, and SPR-17. Thus, the maximum ROE for decisionmaking at this stage of the proceeding based on the information provided in the Sierra filing and limited initial analyses is 9.8%, a full 170 basis points below that proposed by Sierra. There are several reasons the 9.8%median DCF-based ROE should be considered the maximum allowable ROE for Sierra's use in its transmission rates. First, much of the risk associated with investing in common stock equity is grounded in the myriad of things that can cause uncertainty regarding the earnings that may be expected from the company. As may be seen from Dr. Morin's testimony, as well as investment analyst and credit rating agency reports, the primary source of electric utility earnings uncertainty and, thus, risk comes from the generation function, due to volatile fuel costs that make up - 15 - so much of the generation costs especially in situations where market-based competitive rates will not allow automatic recovery of such costs. The transmission business is less risky than the generation business and warrants a commensurately lower ROE. However, the greater risk attending the generation business of the integrated utilities included in Dr. Morin's proposed integrated electric proxy group causes the DCF-calculated ROEs to be higher due to market pricing of the common stock of those companies that is most heavily influenced by the proportionately much larger size of the investment of the companies in the generation business than in the transmission business. Second, while Dr. Morin makes the argument that Sierra's below-investment- grade credit ratings from two of the three major credit rating agencies should result in a higher ROE for Sierra than the average for the investment-grade-rated proxy group, the fact is that Sierra's downgrade to below investment grade was not related to its transmission service,but rather its generation service operations and the purchased power cost disallowances it experienced as a result of its actions during the California energy crisis early in this decade. Thus, not only is Sierra's transmission service business less risky than the integrated utility and diversified businesses of the proxy group, but it was the generation function of the Company that is responsible for its below-investment- grade credit ratings. Therefore, the transmission service at issue in this proceeding should not be saddled with the adverse consequences of the generation supply decisions previously made by Company management. To the contrary, the transmission customers should be insulated from the effects of the higher risks resulting directly from the Company's generation supply actions that the Public Utilities Commission of Nevada found to warrant significant past cost disallowances. - 16 - Finally, the brief time allowed for review and protest of the filing has not afforded the opportunity for sufficient analyses to independently identify a group of predominantly wires utilities with risks more closely matching those of Sierra's transmission business and to properly apply the Commission's standard DCF analytical approach. Thus, reliance on the limited amount of independent risk-assessment data provided in Dr. Morin's Exhibit SPR-17 for purposes of salvaging something of use in evaluating Sierra's proposed ROE based on the integrated and diversified proxy companies included its filing should not be considered as the end result,but rather as the maximum ROE to be used in conducting suspension analyses. The fact is that none of Dr. Morin's analyses, including his DCF analyses, conform to the standards consistently applied by the Commission and cannot be considered to justify the requested 11.5% allowance or anything close to that level. a) Witness Morin's Capital Asset Pricing Model and Other Risk Premium Analyses Should be Rejected Dr. Morin makes use of the risk premium method and applications of the CAPM that do not conform to the single-stage DCF analytical methodology long preferred by the Commission and as more recently refined in Southern California Edison Co., Opinion No. 445, 92 F.E.R.C. ¶61,070, at 61,260-63 (2000) ("So Cal Ed") and subsequent cases for application to electric utilities. All of Dr. Morin's analyses, except for a corrected set of single-stage DCF calculations, should be ignored because they are unreliable and rightly have been rejected by the Commission in the past. - 17 - The Commission very recently affirmed, in Order No. 679,15 its long-standing findings that such analyses are not useful in determining the allowed ROE for electric utilities, even in combination with its standard DCF methodology. In the underlying rulemaking proceeding, a number of commenters "request[ed] that the Commission adopt additional methodologies, such as risk premium, comparable earnings, Fama-French, and/or capital asset pricing, to use along with the current DCF analysis because a multiple model approach will result in a more representative ROE range." Id. at P 99. The Commission squarely rejected those requests, stating that "[o]ur past practice of using the DCF approach has yielded just and reasonable results and is consistent with long-standing ratemaking principles." Id. P 102. In reaching this conclusion in Order 679, the Commission held fast to a long and consistent practice. In So Cal Ed, the Commission had squarely addressed whether it should continue its use of the single-stage DCF method for electric utilities or switch to use of a two-stage or multi-stage method as it had done for natural gas pipeline utilities. The Commission ruled that the two-stage DCF methodology prescribed for gas pipelines was not appropriate for electric utilities and that only a single-stage DCF methodology (a.k.a. the constant growth model)was appropriate. The Commission said, "we believe that significant differences exist in the electric utility industry and the natural gas pipeline industry which warrant the continued use of different growth rates in the DCF models for each." Id.at 61,261. 15 Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 Fed. Reg.43,294(July 31,2006), III F.E.R.C. Stat.&Regs.¶31,222,P 99(to be codified at 18 C.F.R. §§ 35.34-35.35),on reh'g, Order No. 679-A, 72 Fed. Reg. 1,152 (Jan. 10, 2007), III F.E.R.C. Stat. & Regs. ¶ 31,236, clarified, 119 F.E.R.C.¶61,062(2007). - 18 - It is also made clear in Opinion No. 446, System Energy Resources, Inc., 92 F.E.R.C. ¶ 61,119, at 61,446 (2000), reh'g denied, 96 F.E.R.C. ¶ 61,165 (2001), that the Commission develops its allowed rate of return on common equity solely from the results of the DCF model. The opinion stated: Indeed, we note that reliance on the electric constant growth DCF approach is consistent with past practice in electric rate proceedings. We have relied almost exclusively on this approach to set the rate of return on equity for electric public utilities for many years, and we have adopted that approach in several recent orders. Id., footnote omitted. In subsequent opinions, the Commission has confirmed its exclusive use of a single-stage DCF methodology for electric utilities. See, e.g.,New York State Elec. & Gas Corp., Opinion No. 447, 92 F.E.R.C. ¶61,169 (2000), on reh g, 100 F.E.R.C. ¶61,021 (2002), reh g denied, 101 F.E.R.C. ¶61,037 (2002), corrected on reconsideration, 103 F.E.R.C. ¶61,321 (2003).. Consumers Energy Co.,Opinion No. 429, 85 F.E.R.C.¶61,100,at 61,361-62 (1998) ("Consumers"), on reh g, 89 F.E.R.C. ¶ 61,138 (1999), reh g denied, 95 F.E.R.C. ¶ 61,084 (2001), constitutes another example of the Commission's rejection of the methods employed by Dr. Morin. In the Consumers case, three analytical methods were used by the utility's witness, Mr. Moul, in his testimony in the 1992 transmission tariff filing of Consumers Energy Company (formerly Consumers Power Company) in Docket Nos. ER92-331-000 and ER92-332-000 (June 25, 1992). In that case, the Administrative Law Judge and the Commission flatly rejected use of the risk premium analysis, CAPM, and the comparable earnings approach in favor of continued sole reliance on the single-stage DCF methodology. The Commission summarized its rejection of the CAPM method as follows: - 19 - Similarly, the CAPM methodology, which relies on "beta," is not an appropriate mechanism for determining the ROE for an individual company. Trial Staff has identified a number of problems associated with estimating beta that make betas, in isolation, unreliable predictors of risk. Lastly, Mr. Moul's CAPM suffers from his use of long- term bond rates as his proxy of the risk-free rate. The Commission has determined that the Treasury bill rate is a more appropriate proxy. 85 F.E.R.C. ¶61,100, at 61,362, footnotes omitted. As it has done consistently through the years, the Commission should give no consideration to Dr. Morin's alternative approaches to calculating the ROE in this case, and should rely exclusively on a properly formulated DCF analysis. b) Dr. Morin's DCF Analysis is Flawed and Must be Corrected Dr. Morin has not followed the Commission's preferred approach for applying the DCF method and these deviations require correction to his analyses. In addition, Dr. Morin has not demonstrated that the broad electric utility groups he uses are comparable in risk to Sierra, much less the transmission service business of Sierra at issue in this proceeding and, thus, those groups are problematic for use here as well. Dr. Morin multiplies the currently indicated annual dividend yield by one (1)plus the expected growth rate. He should have multiplied the dividend yield by one (1) plus one-half(1/2) of the expected growth rate. This is the formula (k=(D/P) (1 + 0.5g) +g) that the Commission determined to be appropriate in its Order Nos. 420 and 442-A (and subsequent orders) in its 1980s electric utility generic rate of return rulemaking proceedings, and that it has consistently employed subsequently in individual electric utility proceedings. See Generic Determination of Rate of Return on Common Equity for Public Utilities, Order No. 420, 50 Fed. Reg. 21,802 (May 29, 1985), [1982-1985 -20 - F.E.R.C. Reg. Preambles] FERC Stats. & Regs. ¶ 30,644 (to be codified at 18 C.F.R. pt. 37); Generic Determination of Rate of Return on Common Equity for Public Utilities, Order No. 442-A, 51 Fed. Reg. 22,505 (June 20, 1986), [1986-1990 F.E.R.C. Preambles] F.E.R.C. Stats. & Regs. ¶ 30,702 (to be codified at 18 C.F.R. pt. 37); see also So Cal Ed and the other opinions cited above. This specification of the DCF formula is appropriate because it correctly accounts for the standard quarterly payment of and compounding effect of dividends. Dr. Morin's methodology wrongly inflates the calculated results. Dr. Morin's application of the DCF method also deviates from the Commission's preferred methodology in three other major ways. First, he uses a dividend yield calculated based upon a single spot price for the utility rather than a six-month average dividend yield calculation. In applying the DCF method, it is important to develop a dividend yield that is representative of the current market. However, the dividend yield should be developed in a manner that smoothes out any short-term disturbances. The Commission has found that a six-month average best accomplishes this objective unless compelling circumstances indicate a different period is more appropriate. See Blue Ridge Power Agency, 55 F.E.R.C. ¶ 61,509, at 62,783 (1991), on reh g, 57 F.E.R.C. ¶61,100 (1991), on reh g, 58 F.E.R.C. ¶61,193 (1992). Dr. Morin has not even attempted to make any showing of such compelling circumstances, and, thus, his use of a spot dividend yield is not appropriate. A second major problem with Dr. Morin's application of the DCF model is his flotation cost adjustment. To adjust for flotation costs, Dr. Morin divides the expected dividend yield by 0.95. This increases the dividend yield by over 5% and is in direct conflict with longstanding Commission precedent. See New England Power Co., 22 -21 - F.E.R.C. ¶ 61,123 (1983). Dr. Morin assumes an issuance cost of approximately 5% and effectively applies it to the total outstanding common equity capital of the subject utility. Substantiation of the claimed costs must be required and only applied to the amount of new equity capital expected to be issued in the future when the subject rates are expected to be in effect. Id. Dr. Morin has failed to substantiate the 5%cost amount and has failed to make any showing that SPR is expected to make any additional public issuances of common stock over the next several years. Therefore, no flotation cost adjustment should be included in the DCF calculations. This error alone inflates Dr. Morin's recommendation by approximately 30 basis points. Third, and perhaps most importantly, Dr. Morin's DCF analysis deviates from Commission precedent in that he does not use the median of the DCF results for his proxy group. Because this case involves the rates for a single zone within a single company, and in no way involves an RTO-wide rate, and because the median is less likely than the midpoint to be significantly distorted by the sorts of improper proxy selections discussed below, the Commission should look in this case to the median in ascertaining the cost-based component of the equity return. The Commission has found that when selecting an ROE for a single utility, the median is "the most refined measure of central tendency." Midwest Indep. Transmission Sys. Operator, Inc., 106 F.E.R.C. ¶61,302, P 10 (2004), aff'd sub nom Pub. Serv. Comm'n of Ky. v. FERC, 397 F.3d. 1004 (D.C. Cir. 2005). See also Golden Spread Elec. Coop., Inc. v. Southwestern Pub. Serv. Co., 115 F.E.R.C. ¶63,043, P 106 (2006) (adopting median for use in setting wholesale requirements power rates of a single utility), corrected, 115 F.E.R.C. ¶63,054 (2006), exceptions pending. - 22 - This policy is consistent with the Commission's prior ruling upon having been directed to clarify its policy on central-tendency measures. On remand from Canadian Association of Petroleum Producers v. FERC, 254 F.3d 289, 297-99 (D.C. Cir. 2001), the Commission explained that"[s]ince the midpoint is the average of the highest and lowest numbers in the group, it is clearly subject to distortion by extremely high or low values," and that therefore, "the laws of statistics support the Commission's use of the median in setting ROE for a company facing average risk because it has important advantages over the mean and midpoint approaches in determining central tendency." Northwest Pipeline Corp., 99 F.E.R.C. ¶61,305, at 62,276 (2002). See also Kern River Gas Transmission Co., 117 F.E.R.C.¶61,077, P 175 (2006).16 In addition to these calculation flaws, Dr. Morin's DCF analysis is faulty in that he does not use a properly representative proxy group. In his Exhibits SPR-13, SPR-14 and SPR-15, Dr. Morin applies his non-conforming version of the DCF methodology to two broad groups of utilities— 25 "S&P Integrated Electric Utilities" and 19 "Moody's Electric Utilities." Rather than attempt to select a proxy group of companies with risk characteristics comparable to Sierra's transmission operations, Dr. Morin simply used these two broad groups of largely overlapping integrated and diversified companies. He does, however, show some "comparative risk measures" for his S&P Integrated Electric Utilities in his Exhibit SPR-17. While we will leave to the development of testimony for presentation at hearing the selection of a proxy group that is properly composed of companies that are truly comparable 16 Also, in Order No. 679-A regarding transmission incentives, the Commission stated that basing an electric transmission ROE on the median is"an acceptable method." Order No.679-A at P 63 n.105. - 23 - in risk to Sierra's service at issue here, for purposes of this preliminary analysis, we will correct Dr. Morin's DCF analysis using the Commission's approved methodology and those utilities in his S&P group that have the same Value Line Safety Rank of 3 that Sierra Pacific Resources has. As shown on the attached Appendix A, there are 10 such companies. The remaining 15 companies in Dr. Morin's group have Safety Ranks of 1 or 2 indicating lower risk than SPR. Thus, this is a conservative analysis and is likely to result in a higher than necessary ROE, since the heavily generation oriented companies are likely to bear higher risk than the Sierra transmission business at issue here. Furthermore, while we have corrected Dr. Morin's analyses to use the Commission's preferred specification of the DCF formula, k = D/P(1+0.5g) + g, and eliminated the erroneous flotation cost adjustment, we have not yet corrected his use of the spot dividend yields or his use of analysts' 5-year consensus EPS growth rate estimates reported by Zacks Investment Research and similar Value Line estimates rather than the Commission's preferred IBES reported analysts' estimates and the application of the g=br+sv sustainable growth rate formula using Value Line projections. Nonetheless, the corrections we have been able to make for purposes of this protest demonstrate that Dr. Morin's recommended 11.5% ROE is greatly excessive. As shown on Appendix A, our calculated range is 6.2% to 16.9% with a median of 9.8%. This 9.8% median result is the most appropriate for use in determining the proper suspension period for the proposed rates and the question of whether the existing rates are excessive. Of course, at this stage of the proceeding, there is limited information available in the filing on the ROE and overall cost of capital issues, no time to conduct discovery, and little time for in-depth or independent analyses. During the hearing procedures that should -24 - be established, other ROE and capital structure issues may come to light that would impact the allowable overall cost of capital and rates. Therefore, the broader issues impacting the overall cost of capital and allowable rate of return on rate base should be set for hearing in addition to just the level of the appropriate ROE to be used in determining the transmission rates at issue. 3. Non-Firm and Short-Term Firm Transmission Revenue Credits for Period II are Understated In developing Period II (i.e., calendar year 2008) revenue credits, SPR Operating Companies appear not to have projected transactions for short-term firm or non-firm transmission of electricity or for the transmission component of off-system sales. See Exhibit SPR-21, Statement AU and Statement AU Workpaper. Rather, despite a significant increase in such sales from 2005 to 2006, the Companies chose to average 2005 and 2006 sales, producing a figure of just over $2 million, compared to actual revenues of $2.4 million in 2006. Next, Sierra made an "adjustment" to the average figure for one customer(PacifiCorp), bringing the total down to $1.656 million. Finally, Sierra escalated this "adjusted" average figure, in proportion to the proposed transmission rate increase (i.e., the ratio of the proposed $2.97 rate divided by the current $2.88 rate). This calculation produces a proposed Period II revenue credit of$1.7 million. Both the averaging of 2005 and 2006 actual revenues and the PacifiCoip "adjustment" are questionable at best. While the basis for the averaging is not entirely clear, it appears that Sierra attempts to rationalize it by comparing the transaction activity for the first seven months of 2005, 2006 and 2007 (id.). It may be the case that 2007 transactions are lagging 2006 transactions during the first seven months of the year, but this is not indicative of how the year 2007 will end or how 2008 will look. For example, -25 - in 2005 only 23% ((365,875/1,592,345) x 100 =23%) of such sales for the year occurred in the first seven months. Moreover, even with some modest decline in such transactions with PacifiCorp, 2006 showed a substantial increase over 2005. Thus, the Companies' prognostication of a significant reduction in short-term firm and non-firm transactions in 2008 (compared to the 2006 Period I test year) appears to be belied by 2005 and 2006 actual data. The Companies' filing suggests that the proposed "adjustment" to the PacifiCorp transactions was made in light of the Companies' expectation that the advent of additional PacifiCorp generating resources (namely a new generator expected to go on- line in the third quarter of 2007 (id., Statement AU Workpaper, footnote)) will reduce power sales to PacifiCorp. This assumption, however, is built on the notion that PacifiCorp was utilizing non-firm transmission service to serve firm load that will be served with a new generator, a proposition that has not been established. In addition to the problems with the averaging and the PacifiCorp adjustment, the Companies eliminated all billing adjustments reported in 2005 and 2006 associated with short-term firm and non-firm transactions when making their comparisons. Ironically, a review of Sierra's 2005 FERC Form No. 1 ("2005 FF1") and 2006 FERC Form No. 1 ("2006 FF 1") (collectively"FF 1 s") indicates that all such adjustments were positive, thus suggesting that Sierra had consistently underbilled for certain of these services. Although the FF Is do not indicate the nature of or period(s) affected by such adjustments, they are sufficient to raise questions as to the appropriateness of the exclusion of billing adjustments. -26 - If Sierra had simply assumed the same level of short-term firm and non-firm transactions for Period II was reported in the FF1 for 2006 (i.e., no growth) and adjusted for the change in rate, the revenue credits would have been $2.498 million($2,422,679 x ($2.97/$2.88) _ $2,498,388). This means that the revenue credits for short-term firm and non-firm transmission are likely understated by at least $790,000 ($2.498 - $1.708 = $0.790). This error alone equates to an overstatement of the requested rate by $0.04/kW- month ($790,000/(1,645,000 x 12) _ $0.040), or almost half of the proposed $0.09/kW- month proposed increase. 4. Cash Working Capital Requirement is Overstated by Reliance on the One-Eighth Rule Sierra's transmission cost-of-service analysis relies upon the automated calculation of cash working capital based upon the one-eighth rule ("1/8 rule") (i.e., 1/8 of operation & maintenance ("O&M") expense less fuel and purchased power) (see, e.g., Exhibit SPR-20 at 76, Statement BK, Schedule 3 at 3:13). The 1/8 rule often becomes the default method when a utility elects not to produce and rely upon a fully developed and reliable lead/lag cash working capital analysis. It is to be expected that a fully developed and reliable lead/lag analysis would show that no cash working capital allowance is required. This contention is based on the results of recently accepted lead/lag analyses submitted to the Commission in other rate cases, including those prepared by the filing utilities themselves. Deletion of the cash working capital requirement would reduce the Period 11 transmission revenue requirement by about $85,000. -27 - 5. The Prepayments Component of Rate Base is Overstated Sierra's cost-of-service analysis classifies prepayments associated with working capital into various components for cost allocation (see, e.g., Exhibit SPR-21, Statement AL, Workpaper 4 Categories of Prepayments). One of such prepayments assigned to transmission is a direct assignment of prepaid transmission expense (Account 165.301) (id.) totaling $475,000 for Period II. Given that the filing properly excludes Account 565 —Transmission by Others from transmission O&M expense allocated to the transmission function (id., Statement BK, Schedule 4 at 1:14), it should also exclude prepaid transmission expense from rate base. Deletion of this component of prepayments reduces the transmission revenue requirement by about$50,000. 6. Transmission Plant Included in Rate Base for Period II may be Excessive As noted above, the filing claims that one of the primary drivers of the proposed rate increase is new transmission investment. One of the cited transmission projects is the West Tracy 345 kV Substation which is projected to be in service in September 2007 at a cost of $10.952 million (Exhibit SPR-1 at 6). The filing describes this project as follows: The West Tracy 345 kV substation will integrate the new gas turbines into Sierra Pacific's existing Tracy Generating Facility. This new 345 kV Substation will include five 345 kV terminals: one each for two combustion turbines, one for the heat recovery steam generator, and two for the line terminals needed to intersect the existing Tracy-Mira Loma 345 kV line. The breaker replacements will consist of four different 120 kV breaker replacements at Valley Road, North Valley Road, Mira Loma and Tracy. Id. at 7. It appears that this entire investment has been included in transmission plant for purposes of determining the proposed transmission rate. The above description of the -28 - West Tracy 345 kV Substation, however, indicates that portions of the associated investments may be Interconnection Facilities pursuant to Order No. 2003 and its progeny.17 Pursuant to Order No. 2003, all Interconnection Facilities associated with a Transmission Owner's new generation installed on and after March 15, 2000, must be directly assigned to the Transmission Owner. It is unclear from the information in the filing, however, as to what portion of the new facilities should be so directly assigned. Such direct assignment will have the effect of reducing the costs upon which Sierra's OATT transmission rate should be based. Discovery will be required to determine the extent of the adjustment necessary to conform the allocated cost-of-service study to the requirements of Order No. 2003. 7. Allocations of Other Prepayments to Transmission are Questionable Sierra includes $11.686 million of Common Prepayments in its allocated cost-of- service analysis (Exhibit SPR-21, Statement BK, Schedule 3 at 3:10, see, Statement AL Workpaper at 2). Included within the $11.686 million is $7.525 million (id.) which is broadly labeled prepayments. Without further details, it is impossible to know whether further refinement of the classification of prepayments is required for cost allocation purposes to exclude items unrelated to transmission service. Similarly, there is an item of $178,000 labeled Prepaids, which is also unexplained. There is an item labeled Prepaid " Standardization of Generator Interconnection Agreements and Procedures,Order No.2003,68 Fed.Reg. 49,846 (Aug. 19, 2003), [2001-2005 Regs. Preambles] F.E.R.C. Stat. &Regs.¶31,146 (to be codified at 18 C.F.R. pt. 35), modified, 68 Fed. Reg. 69,599 (Dec. 15, 2003), clarified, 69 Fed. Reg. 2135 (Jan. 14, 2004), 106 F.E.R.C. 161,009 (2004), order on reh'g, Order No. 2003—A, 69 Fed. Reg. 15,932 (Mar. 26, 2004), [2001-2005 Regs. Preambles] F.E.R.C. Stat. & Regs.131,160, order on reh'g, Order No. 2003-13, 70 Fed. Reg. 265 (Jan. 4, 2005), [2001-2005 Regs. Preambles] F.E.R.C. Stat. &Regs.¶31,171, order on reh g, Order No. 2003—C, 70 Fed. Reg. 37,661 (June 30, 2005), [2001-2005 Regs. Preambles] F.E.R.C. Stat. & Regs. ¶ 31,190, affd sub nom. NARUC v. FERC, 475 F.3d 1277 (D.C. Cir. 2007) ("Order No. 2003"). -29 - Taxes — NV, of $1.603 million which is unexplained and requires review to determine whether Sierra's proposed allocation is appropriate. Finally, there is a series of prepaid items Assigned to Electric Common totaling $474,000 (id.) which is allocated in part to transmission, without explanation. Without further information, it is impossible to determine whether Sierra's proposed allocation is just and reasonable. 8. General and Intangible Plant Functionalization and Allocation Requires Scrutiny Period 11 Electric Plant In Service includes $105.287 million for general and intangible plant, a portion of which is allocated to transmission based upon wages and salaries (Exhibit SPR-21, Statement BK, Schedule 2 at 1:5). No details of the composition of this general and intangible plant investment have been provided. In today's environment, it is common for such plant to include sizeable investments in software associated with retail customer information systems. Such investments should not be allocated to transmission customers. Additional information will be required as to the nature and level of the various and intangible plant investments to determine how such costs should be allocated. Similarly, Sierra's allocated cost-of-service analysis includes common plant of $124.412 million(id. at 1:6) which is allocated based on total company wages and salaries (as contrasted to electric wages and salaries used for general and intangible plant allocations). Likewise, no investment details are provided for these common plant investments. A review of common plant as detailed in the 2006 FF1 (at 356) shows that a substantial amount of such investment ($54.108 million) is associated with software. For the same reasons noted with regard to intangible plant, details regarding this investment are required to determine the appropriate method for cost allocation. In addition, the - 30 - remaining components of common utility plant need to be examined to determine if the total company wages and salaries allocator is the appropriate method for allocation of such investment. C. The Proposed Rate Should Be Suspended for Five Months and Made Subject to Refund, and the Commission Should Initiate a Section 206Investigation Based on Period II costs as adjusted to correct quantifiable flaws in the allocated cost of service, not only is the proposed rate of $2.97/kW-month excessive, but the underlying rate of $2.88/kW-month proposed to be superseded is excessive, as shown below. Transmission Revenue Requirement Rate (000's) $/kW-Month As-filed Period II $58,567 $2.97 Reduce return on equity to 9.8% $54,495 $2.76 Set short-term firm and non-firm revenue credits at Period I (2006) levels with adjustment for the proposed rate $53,705 $2.72 Zero Cash Working Capital $53,620 $2.72 Delete prepaid transmission expense from prepayments $53,570 $2.72 Use FF1 Native Load for 2006 in $53,570 $2.66 determining the divisor In short, preliminary analysis and correction of Sierra's filing demonstrates that the just and reasonable rate should not exceed $2.66/kW-month, which is considerably lower than the existing rate. The Commission's policy provides for five-month suspension of proposed rate increases that are found likely to be excessive by more than - 31 - 10%. West Tex. Utils. Co., 18 F.E.R.C. ¶ 61,189 (1982). In this case, the entirety of the proposed rate increase is unjust and unreasonable, inasmuch as a rate reduction, rather than any rate increase, is indicated. Thus, the proposed rate increase should only become effective after the maximum five-month suspension and subject to refund with interest. In addition, a Section 206 investigation should be initiated, and the Commission should establish a refund-effective date at the earliest date permitted by law and the Commission's regulations. III. CONCLUSIONS For the foregoing reasons, the Commission should • grant Truckee's motion to intervene and allow it to participate with full rights as a party, • find that the SPR Operating Companies' proposed use of stated rates for network transmission service in Zone A is not just and reasonable, • alternatively, and at minimum, set for hearing whether that rate design is just and reasonable in the circumstances of this case and whether updating or any other modification is required, • suspend the proposed rate increase for the maximum five-month period, and thereafter place the new rate into effect subject to refund, • initiate an investigation pursuant to Federal Power Act Section 206 into whether the last clean rate is excessive, and establish the earliest possible refund-effective date for any rate reduction that may be ordered, and - 32 - • set for hearing all issues related to Sierra's cost of service and establish settlement judge procedures. Respectfully submitted, ls/ Margaret A. McGoldrick Margaret A. McGoldrick Jeffrey A. Schwarz Attorneys for Truckee Donner Public Utility District Law Offices of: Spiegel &McDiarmid LLP 1333 New Hampshire Avenue,NW Washington, DC 20036 (202) 879-4000 October 5, 2007 APPENDIX A Appendix A Sierra Pacific Resources Operating Companies Docket No. ER07-1371-000 Corrections to Dr. Roger A. Morin's S&P Group and DCF Model Calculations Exhibit Exhibit Exhibit Value SPR-13 SPR-13 SPR-14 Line Current Value Analysts' Safety Dividend Line EPS EPS ICOE=(DIP)(1+0.5g)+g Line Rank Yield Growth Growth Implied Cost of Equity No. Company VL_q Analysts'a 1 ALLETE, Inc. 2 Alliant Energy 3 3.4% 5.0% 6.0% 8.5% 9.5% 3 American Electric Power 3 3.7% 6.5% 4.7% 10.3% 8.5% 4 Ameren 5 Cleco Corp 3 3.6% 4.0% 12.0% 7.7% 15.8% 6 DTE Energy 3 4.5% 4.0% 5.7% 8.6% 10.3% 7 Edison International 3 2.1% 6.5% 9.3% 8.7% 11.5% 8 Empire District Electric 3 5.6% 11.0% 3.0% 16.9% 8.7% 9 Energy East Corp 10 Entergy Corp 11 FPL Group 12 FirstEnergy Corp. 13 Hawaiian Electric 14 IDACORP Inc. 3 3.7% 2.5% 6.0% 6.2% 9.8% 15 MGE Energy 16 Northeast Utilities 3 2.8% 12.0% 13.0% 15.0% 16.0% 17 PG&E Corp 18 PNM Resources 19 Pinnacle West Capital 20 Progress Energy 21 Puget Energy Inc. 3 4.1% 6.0% 5.5% 10.2% 9.7% 22 Southern Co 23 TECO Energy 3 4.6% 4.5% 6.0% 9.2% 10.7% 24 Wisconsin Energy 25 Xcel Energy, Inc. Range 6.2% 16.9% Median 9.8% Sierra Pacific Resources 3 Source: Morin Exhibits SPR-13, 14, and 17, in Docket No. ER07-1371-000. CERTIFICATE OF SERVICE CERTIFICATE OF SERVICE I hereby certify that I have on this 5th day of October, 2007, caused the foregoing document to be sent by electronic mail to all parties on the list compiled by the Secretary of the Commission in this proceeding. ls/ Margaret A. McGoldrick Margaret A. McGoldrick Law Offices of- Spiegel &McDiarmid LLP 1333 New Hampshire Avenue,NW Washington, DC 20036 (202) 879-4000