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Home My WebLink About20080102Micron to IPC 1-2.pdfIdaho Public Utilties Commission Office of the SecretaryRECEIVED GIVE SLEY LLP DEC 3 1 2007 Boise, Idaho lAW OFFICES 601 W. Bannock Street PO Box 2720, Boise, Idaho 83701 TELEPHONE: 208 388-1200 FACSIMilE: 208 388-1300 WEBSITE: ww.givenspursley.com Gary G. Ailen Peter G. Barton Christopher J. Beeson Clint R. Bolinder Erik J. Bolinder Willam C. Cole Michael C. Creamer Amber N. Dina Kristin Bjorkman Dunn Thomas E. Dvorak Jeffrey C. Fereday Martin C. Hendrickson Steven J. Hippler Debora K. Krstensen Anne C. Kunkel Jeremy G. ladle Michael P. lawrence Franklin G. lee David R. Lombardi John M. Marshail Kenneth R. McClure Keily Greene McConneil Cynthia A. Meliilo Christopher H. Meyer L. Edward Miiler Patrick J. Miler Judson B. Montgomery Deborah E. Nelson W. Hugh O'Riordan, lL.M. G. Andrew Page Angela M. Reed Scott A. Tschirgi, lL.M. J. WiilVarin Conley E. Ward Robert B. White Tem R. Yost RETIRED Kenneth L. Pursley Raymond D. Givens James A. McClure December 31, 2007 Via Hand Delivery Jean Jewell Idaho Public Utilities Commission 472 W. Washington P.O. Box 83720 Boise, ID 83720-0074 Re: Our File: In the Matter of the Application of Idaho Power Company for Authority to Increase its Rates and Charges for Electrc Service to Electrc Customers in the State of Idaho - Case No.: IPC-E-07-08 4489-29 Dear Jean: Enclosed for fiing are an original and four (4) copies of Micron Technology, Inc.'s Response to Idaho Power Company's First Production Request in connection with the above-captioned matter. If you have any questions, please call me. j=\n.aJ~ Tina M. Adornetto Assistant to Conley Ward CEW/tma cc: Service List (w/enclosures) S:\CLIENTS\4489\29\T A to Jewell re Micron Response to ¡PC i st Production Request.DOC Conley E. Ward (ISB No. 1683) GIVENS PURSLEY LLP 601 W. Bannock Street P. O. Box 2720 Boise, ID 83701-2720 Telephone No. (208) 388-1200 Fax No. (208) 388-1300 cew(0givenspurs1ey,com Ido Put;';" ¡.'I."..'t', vi'! '~s COffce of l~e'š ommission R E C E, v~~taiy DEC 3 f 2007 Boise, Idaho Attorneys for Micron Technology, Inc. S:\CLlENTS\4489129\Micron Response to IPC 1st Producton.DOC BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPAN FOR AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC SERVICE TO ELECTRIC CUSTOMERS IN THE STATE OF IDAHO Case No. IPC-E-07-08 MICRON TECHNOLOGY, INC.'S RESPONSE TO IDAHO POWER COMPANY'S FIRST PRODUCTION REQUEST COMES NOW Micron Technology, Inc., by and through its attorneys of record, Givens Pursley LLP, and hereby responds to Idaho Power Company's First Production Request to Micron Technology, Inc. as follows: REQUEST NO.1: Please provide copies of testimony and exhibits or comments Dr. Peseau has prepared and/or presented in utility revenue requirement cases during the past five (5) years which address the use of forecasted test years, and utility cost of service issues. Testimony and comments presented in cases in which Idaho Power was a party do not need to be provided. RESPONSE TO REQUEST NO.1: Copies attached hereto. MICRON TECHNOLOGY, INCo'S RESPONSE TO IDAHO POWER COMPANY'S FIRST PRODUCTION REQUEST - IPC-E-07-08 - PAGE 1 REQUEST NO.2: During the time when Dr. Peseau was employed by the Public Utilities Commissioner of Oregon, did the Oregon Commissioner approve a forecast test year. If yes, please describe the forecast structure approved by the Oregon Commissioner. RESPONSE TO REQUEST NO.2: No.$J DATED this 3/ day of December, 2007. ~~7 GIVENS PURSLEY LLP Attorneys for Micron Technology, Inc. MICRON TECHNOLOGY, INCo'S RESPONSE TO IDAHO POWER COMPANY'S FIRST PRODUCTION REQUEST - IPC-E-07-08 - PAGE 2 CERTIFICATE OF SERVICE I HEREBY CERTIFY that on this 3\~ day of December, 2007, I caused to be sered a true and correct copy of the foregoing by the method indicated below, and addressed to the following: Jean Jewell Idaho Public Utilties Commssion 472 W. Washington Street P.O. Box 83720 Boise, il 83720-0074 )Z U.S. Mail Hand Delivered Overnght Mail Facsimile E-Mail Baron L. Kline Monica B. Moen Idaho Power Company P.O. Box 70 Boise, il 83707 email: bklineG!idaopower.com x U.S. Mail Hand Delivered Overnght Mail Facsimile E-Mail JohnR. Gale Vice President Regulatory Affairs Idaho Power Company P.O. Box 70 Boise, il 83707 email: rgaleG!idaopower.com )(U.S. Mail Hand Delivered Overght Mail Facsimle E-Mail Peter 1. Richardson Richadson & O'Lear 515 N. 27th Street Boise, il 83702 email: peterG!nchadsnadoleai.com x U.S. Mail Hand Delivered Overght Mail Facsimile E-Mail Enc L. Olsen Racine, Olson, Nye, Budge & Bailey Charered P.O. Box 1391 201 E. Center Pocatello, Idaho 83204-1391 email: rcbßYcinelaw.net )(U.S. Mail Hand Delivered Overnght Mail Facsimile E-Mail Anthony Yanel 29814 Lake Road Bay Vilage, Ohio 44140 email: yanelG!attbi.com )( U.S. Mail Hand Delivered Overnght Mail Facsimile E-Mail Lu.s.MailHand Delivered Overnght Mail Facsimile E-Mail Dr. Don Reading 6070 Hil Road Boise, Idaho 83703 email: dreadiniWmindspnng.com MICRON TECHNOLOGY, INC/S RESPONSE TO IDAHO POWER COMPANY'S FIRST PRODUCTION REQUEST - IPC-E-07-08 - PAGE 3 .. Weldon Stutzman Neil Price Deputy Attorney Generals Idaho Public Utility Commssion 472 W, Washington (83702) P,O, Box 83720 Boise, Idaho 83720-0074 Email: weldon.stutzrnan(~iipuc.idaho,gov N eil.príce(êílpuc. idaho, g ov Michael Kur, Esq. Kur J. Boehm Esq. Boehm Kur & Lowr 36 E, Seventh Street, Suite 1510 Cincinnati, OH 45202 email: mlqii;!z(qiEKlJit\yllrm,çQm k!_Q.I):)l.l(~m~KLl:l~'\i1i;1.çQm LotH. Cooke United States DOE 1000 Independence Ave, SW Washington, DC 20585 email: lot.cooke(mhq.doe.gov Dale Swan Exeter Associates, Inc. 5565 Sterrett Place, Suite 310 Columbia, MD 21044 Email: dswan(w.exeterassociates.com Electronic Copies Only: Dennis Goins Email: dgoinsprng(mcox~net Arthur Perry Bruder Email: l\rthur.bmder((l)hq.doe.goíí ~us.Mail Hand Delivered Overnght Mail Facsimile E-Mail -¥ US, Mail Hand Delivered Overnght Mail Facsimile E-Mail ~us.Mail Hand Delivered Overnight Mail Facsimile E-Mail x U,S, Mail Hand Delivered Overnght Mail Facsimile E-Mail MICRON TECHNOLOGY, INC.'S RESPONSE TO IDAHO POWER COMPANY'S FIRST PRODUCTION REQUEST - IPC-E-07-08 - PAGE 4 HALE LANE ATTORNEYS AT LAW 171 F.asl Wiliam Si0:1 I Suii.:i! Cai:'n Ciiy. NUYad¡i K9701 TelephQne (775) 684-6UOo . I'a"simile P75)t,Sl-61 ,liww.liaklati.,coll March 19, 2007 . :~ ~~ . ,-.1'.. ::; Crystal Jackson Commission Secretar 1150 E. Wiliam Stret Carson City, NV 89701 ::~:. ~ : ;~~l.fJ'¿. _.--_. õ.(¿';'r\ "'.1':J .-: ~.. RE: DOCKET NO. 06- i 1022 C."o ,'0')(::, Dear Ms. Jackson Please accept for fiing the enclosed original and nine copies of the Direct Testimony of Dennis E. Peseau in Phase iv on behalf of Southern Nevada Water Authority in the abovc. referenced docket. Should you have any questions regarding this lilng, please contact meat (775) 684-6000. Sincerely,:4~~ i:red Schmidt, Esq. FJS:taw Enclosures cc: Parties of Record HALE I.AN"; PEEK Dl.NNISON..\ND HOWARD RE"IO oii:ICE: 5441 Kiekclaiiei Swund fluor I Rci. Neii"d.i .951111,1,01'" 1175j3~1.3UOO I facsimile (115) 786-61ì9 LAS VEGAS OFFICE: 39311 Hu\\ iird Hu&hes Parkway I F'1\nh flour I Lo. Ve¡\l, i"ev;id &9161 I i'hue (702) 222.2500 I YIK.imilc (702) :l5.6'l40 :'OIlMAII'CDOS\IILltNODOCSI612368\1 J ... .. ~ i 2 3 4 5 6 7 8 9 10 11 Q. 12 A. 13 14 15 Q. 16 A. 17 is 19 Q. 20 A. 21 22 23 Q. 24 25 A. 26 27 Q. 28 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA Docket No. 0&-11022 ~ C~ !4..r.~5-.J ~.._;¡ Direct Testimony of . Dennis E. Peseau ;.:1 _,';,-i . '.~I: -)~; ::: :~~ ::~~ ,;,) ~. .1 -: :..t: on behalf of Southern Nevada Water Authority i: ..~o "., ~; ~0 PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. My name is Dennis E. Peseau. My business address is 1500 Ubert Stret S.E., Suite 250, Salem, Oregon 97302. BY WHOM ÁND IN WHAT CAPACITY ARE YOU EMPLOYED? I am President of Utilit Resources, Inc. The firm consults on a number of economic, financial, and engineering matters for various private and public entities. ON WHOSE BEHALF ARE YOU TESTIFYNG IN THIS PROCEEDING? I am testifng on behalf of the Southern Nevada Water Authoriy (IlSNWAIt) and it constituent members. DOES ATTACHMENT 1 ACCURATELY DESCRIBE YOUR BACKGROUND AND EXPERIENCE? Yes. WHAT IS THE PURPOSE OF YOUR TESTIMONY? ::ODM\PLROOOC1202\1 Page 1 1 A. 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Q. 19 20 A. 21 22 23 24 2S 26 27 28 My testimony in this Phase IV cost of servce and rate design portion of Docket No. o 06-11022 focuses on tw narrw cost of service and rate design issues. Nevada Power in its Certifcation and originally-filed cost of servce stuy has made a signifcant and inconsistent change in the manner in which it allocates costs to the water pumping classest compared with the tw prir general rate cases Docket Nos. 01-10001 and 03-10001. The purpse of my testimony is to show that the change made to the cost allocation is only to the water pumping classes, is discriminatory, unreasonable and unjust. Correting this change or error wil have an insignificant effect on all other rate classes, although the corrction win measurably affect water pumping classes. Correcting Nevada Power's errr will also ensure that the same consistent cost allocaors are use for all rate classs. Du to the fact that Nevada Power carries its cost of servce results from its bundled rate design to distrbution-only or DOS rates, i also propose a small corrcton to related DOS rates to time differentiate demand charges. WHAT RECOMMENDATION DO YOU MAKE WITH RESPECT TO THE TWO COST OF SERVICE AND RATE DESIGN ISSUES YOU DESCRIBE ABOVE? In order to eliminate the clearly discriminatory rates produced by Nevada Power's cost of service changes only to water pumping classes, i recommend that the Commission order the Company to correct the cost allocation to water pumping classes to: For the Traditional Bundled Water Pumping IWP) Rate Schedules: 1. Allocte the cO$ of distribution demand nonrevenue feeders on the basis of probabilty of peak ("POP") for water pumping classes, just as Is done for every other rate clas and as the Commission previously adopted in Docket No. 01-1001; ::ODM'oCDOCLROOOCS\612n82\1 Page2 ' i 2 3 4 S 6 7 8 ,9 10 11 12 DISTRIBUTION DEMAND COSTS ., 13 14 .Q. 15 16 A. 17 18 19 20 Q. '21 A. 22 23 24 25 26 27 28 2.Alternatively, the Company should scale thse nonrevenue feeder costs on the same basis as it recommended and the Commission adopted In Docket No. 03-10001, that is, on time differentiated kwhs', or the coIncident peak demands (probabilty of peak) of otherwise applicable classes ("OAC"). For Distrbution Onli.Service (DOSLC'asses: 3. The DOS rate design should be Improved to include a time-diffrentiated kW demand charge consistent wit its calculation of time difrentiated nonrevenue feeder demand costs for other demand metered rate schedules. WHAT is THE ISSUE YOU RASE REGARDING THE MANNER IN WHICH NEVADA POWER PROPOSES TO ALLOCATE DISTRBUTION DEMAND COSTS? Nevada Power has deviated from the method for allocating distribution demand costs to all water pumping classes ordered in both Docket Nos. 01-10001 and 03-1,0001. explain the technical aspects of this change below. WHAT AR "DISTRIBUTION DEMAND COSTS?" In Nevada Power's Certification filing, it provides its revised cost of service study (exibit-Walsh Certiftion-2). As has been customary, the cost stdy establishes all required revenues as a funcn of distrbuton, transmission and generation before classifyng into demand, energy and customer cost functions. For reference, the distrbution demand cost category I am concmed wih and address is th residual distributon category of -nonrevenue feeder". ~age 8 of 55, line , 45, of Exhibit-Walsh Certlflcaion-2 calculates the marginal. demand revenues for this distributon demand to be $188.8 millon. ::ODMA\PCDOLR0D01201 Page 3 . 1 2 3 4 5 6 7 8 9 10 Q. 11 A. 12 13 14 J5 16 17 18 19 20 21 22 23 Q. 24 2S A. 26 27 28 As shown on page 8 of this exhibit, this $188.8 milion is allocated to On, Mid, Of and Other demand periods because they are cause by probabilit of distributin coincident peak demands by time of use. Despite its conclusion in this regard, Nevada Power makes an unexplained exception here for all Wp. rate schedules by allocating these distrbution demand costs only to WP schedules on a new and inconsistent basis. This new and unjustified change is not only inconsistent with coincident peak allocation, but is inconsistent with the decisions made by the Commission In both Docket Nos. 01-10001 and 03-10001. WHAT IS THE EFFECT OF THIS CHANGE PROPOSED BY NEVADA POWER? This single change reults in rates propose for the water pumping classes that are discriminatory, in that only these crasses are arrocated costs in this manner. Art other classes have allocators based on previusly approved cost of servce principles applied consistently and equally across all classes except for water pumpers. The resulting rates to water pumping classes proposed by the Company are unjust and unreasonable because. as i calculate below, the arbitrary change proposed here results in a five-fold increase In costs allocated to water pumping rate classes. And, while colTcting this cost allocation to the water pumping schedules has no signifcant impac on all othr rate schures, Nevada Power's change nevertheless reslt in overall water pumping rates being almost 10% higher than they would be under prior Commission-approved cost allocatins. WHAT IS THE HISTORY OF THIS ISSUE IN PRIOR GENERAL RATE CASES, DOCKET NOS. 01-10001 AND 03.10011 On behalf of the SNWA, our finn discovere an errr made by Nevada Power in Docket No. 01-10001 Wih repec to it cost of sece aJlocation of distrbutn demand costs for the water pumping (WP) rate scedules. ::ODM\PCDS\HLRNOOCS\6120821 Page 4 i 2 3 4 5 6 7 8 9 10 i i 12 13 14 Q. 15 A. 16. 17 Q. 18 19 A. 20 21 22 23 24 Q. 2S 26 27 A. 28 The errr was simply that the Company had elected to use customer usage or biling detenninant data, not frm the actal and readily available WP usage dat by time of use, but instead frm what it termed "otherwise appUcabJe classes "(OAe) usage data regardless of time of use. The Commission recognized the Companys inconsistency and found at Ordering Paragraph 585: The Commission finds that the proposal of the SNWA to base the scedule LGS-WP and LGS-X-WP classe' energy BTGRs upon the marginal cost study and not the classes' otherwise applicable rates is reasonable and approved. As a,result, the WP rates in that case were based on WP usage data by actual time of use, not the Copany's proposed method of using OACs' energy or kWh data. reardless of time of use. WAS THE SAME ISSUE DELIBERATED IN DOCKET NO. 03-100011 Yes. WHAT WAS THE COMMISSION DECISION ON THIS ISSUE IN DOCKET NO. 03- 100017 The Commission revised its prior decision and found that Nevada Power could allocate WP demand costs on the basis of the energy data of otherise applicable classes or "OAC.1t This decision increased WP rates signifcantl over the rates that would have resulted if actual WP data had been use. SO, IS THE ISSUE YOU RASE IN REGARD TO WP DISTRIBUTION DEMAND ALLOCATION IN THE PRESENT CASE MERELY A REHASH OF THE ISSUE WP CLASSES RAED IN DOCKE NO. 03-100011 No. , provide thIs history so the Commission has a frme of reference for the new discriminatory approach applie by Nevada Power to the detriment of water pumpIng ::ODMA'lDO\HLRNDO\612081 Page 5 . 1 2 3 4 5 6 .7 8 9 10 Q. 11 A. 12 13 14 15 16 17 18 19 20 Q. 21 A. rate scheules in this case. The issue is new, as Nevada Power has not use either of the specifc allocators approve in the previous general rate ~ses. I also provie, . ~is background to carefully demonstrate that in the present case, Nevada Power has inexplicably deviated from the very same method on this issue that it argued and won in Docket No. 03-10001. This new method propose for allocating distbution demand costs to WP classes results in an approximately five-fold incrase in demand cots allocated tó the WPclasses. HOW DO YOU PROPOSE TO EXPLAIN THIS RATHER TECHNICAL ISSUE? i develop below tw tables intended to clearl identif th disribution demand costs at issue here; to highlight that all other rate classes, including residential and LGS class, are aJJocted these distbution demand costs based on a diferent, and proper, basis; that Nevada Power no longer uses Its propod and authorize OAe _ rate frm OAe kilowatt hours approved Docket No. 03-10001; and, finally, that use of the Commission approved method in Docket No. 03-.10001, while higher than use of actual WP time of use data, would allocate fewer demand costs to WP classes than Nevada Powets new and unexplained noncolncident methd. WHAT ARE THE DISTRIBUTON DEMAD COSTS AT ISSUE HERE? The distrbution demand costs at issue here are calculated by Nevada Power as a and substation demand investment and facilities22residual after all other fixed 23 investmnts are removed: 24 11/ I 25 /III 26 11/ I 27 1/1/ 28 ::ODM\POCS\LRNOD1201 Page 6 - 1 2 3 4 5 6 7 8 9 10 11 12 Q. 13 14 A. is 16 17 is 19 20 21 22 23 24 25 26 27 28 Total New Distribution Plant Investment ($) less - Demand-Related Substation ($) less - Non-DemandlFacifites ($) less Facilities Investment ($) equals = Residual Demand-Drien Distrbuton Investment ($) This residual demand..rlven investment ;s sometimes referr to by Nevada Power and others as Iinon-revenue feeder demand." I will simply refer to this reidual as distribution demand. WHAT ARE THE ACCEPTED COSTING PRINCIPLES FOR ALLOCAnNG DISTRIBUTON DEMAND COSTS? Nevada Powets cost study determines and calculates the extent to which these demand costs are caused by system peak demands and the probabilty of when these demands occr. After concluding this, the Nevada Power cost of servce study then goes on to calculate precise "Probabilit of Peak" or POP coincident peak allocators used to separate these demand costs into the approprite peak, mid peak, off peak and "other" time of use periods. System peak demand allocators are measure by the POP, or similar measures of coincident peak demands in Nevada Powets cost study. The Company does, in fact, arrocate cost of distbution demand on the basis of POP for all rate classes, except for water pumping, as Is shown in Appendix A, Workaper 3. page 23 of 55 in Exhibit..Walsh Certifcation-2. The basis for using such POP demand allocators is usually the result of these demand costs being caused by time-iferentiated peak and off-peak cot causation. Nevada Powets cost study determined that over 90% of the reidual distrbution demand costs are allocated to summer peak periods becuse 90% of the probabilit of ::ODMA'lCDO\HLR0D1201 Page 7 1 2 3 4 5 Q. 6 7 A. 8 9 10 11 12 13 14 Q. 15 16 17 18 A. 19 20 21 22 23 24 25 26 27 28 HOW DOES NEVADA POWER ALLOCATE THESE DEMAND COSTS TO THE WP CLASES? Unlike the Docket No. 03-10001 cåse where Nevada Power requested and was authorized to set WP rates on the basis of energy billing determinants for otherwse applicable cfasses (1I0AC"). the Company in the present case uses what ;s referred to as a "noncoincident" load allocator for the WP classes only. Non concient peak demands have no time of use component. This is simply 8 sum of customer or class maximum demands reardless of when they ocr. . IF, AS NEVADA POWER'S STUDY CONCLUDES, OVER 90% OF THE DISTRBUTION DEMAND COSTS AR CAUSED BY COINCIDENT PEAK LOADS. IS IT PROPER TO ALLOCATE DISTRIBUTION DEMAND COSTS TO WP CLASSES ON NONCOINelDENT LOADS? No. 1 make tw. points in this regard. Firs, there Is never a basis fg mixing. . coincident and noncoincident demand allocators among difrent customer classes as Nevada Power has propose. If system peak loads are driing the need for distrbuion investment, then logically all classes should face these time diferential rate or price signals. If these demand costs are not driven by sysem peak, thn none of the costs of rate classs shOLl1d be allocated on the POP basis. The second point is that this unexplained and peculiar exception made for th WP classes has a disproportonate and advers rate impact on WP classs. 1 See exhibit Walsh Certiftion page 8 of 55, line 45. ratio of -on- to -Total-. ::00'ILRN12082\1 PageS 1 Q.WHERE IN NEVADA POWER'S TESTIMONY OR COST STUDY IS THIS WP 2 EXCEPTION IDENTFIED OR EXPLANED? 3 A.Nowhere. The only way in which one can identif this discnminatory treatment of the 4 WP classes is to carefully examine fonnulae for actal cost allocations In the 5 Company Workpapers. 6 7 Q.HOW DID YOU DETERMINE THAT THE COMPANY'S NEW WP DISTRIBUTON 8 DEMAND ALLOCATOR HAS A DISPROPORTIONATELY ADVERSE EFFECT ON 9 THE WP CLASSES? 10 A.I detennined this by companng the Company's proposed cost allocation to the WP ll classs using it new distrbuton deman allocaor, compared with th cost allotions 12 that would have resulted from using eitr the Docket No. 01-10001 or the Docket No. 13 03-10001 approved alloctors. as shown: 14 15 Kwh Scaed Prosed POP Allocted OnOAC NCPScaed 16 (#01-10001)(#03-10001 ) 17 LGS-2-WPS 104,927 151,132 570,584 18 LGS-2-WPP 41,092 40,820 74,214 19 LG5-2-WPT 20 LG$-3-WPS 9,058 81,635 160,54 21 LG5--WPP 73,107 192.279 474,446 22 23 Tota 228,183 465.866 1,279,791 24 25 Index 1.00 2.04 5.61 26 27 28 /III ::OD\PCOLRNDO\612081 Page 9 1 Q. WHAT DOES THIS TABLE SHOW? 2 A. The table compares the diferences in the amount of distrbution demand costs 3 allocated to the WP rate classes frm the allocators authorize in Docket No. 01-10001, 4 Docket No. 03-10001, and the Company's newly proposed non~incldent caNep") allocator, 5 which is not based upon the same time diferentited allocators used for other classes. 6 For ease of comparin, I index the lowest level of costs as -1- and the higher 7 allocators are scled accrdingly. As is evident, Nevada Powets new distribution demand 8 allocator rNCP allocator") increases the amount of these distribution demand costs 9 dramatical1y, up to 550% over the allocation factor previously used for the WP classes, and to that used in the present study for all other bundled retail rate classes. The WP classes have 11 been unfairly single out here, and with an allocator that is not in accrdance wih the pri 12 system peakalloctors use forWP classes and presently for all other rate classs. 13 14 Q. IS YOUR OBJECTION TO THIS ALLOCATOR BASED SOLELY ON THE FACT 15 THAT IT SIGNIFICANTLY INCRESES THE AMOUNT OF DEMAND COSTS TO WP 16 CLASSES OVER THAT WHICH WOULD RESULT FROM PREVIOUSLY APPROVED 17 DEMAND AlLOCATORS? 18 A. No, although higher costs and resulting higher rates are always a concern for WP 19 classes and, for that matter, all Nevaa Power customers. However, in the present instanc, 20 Nevada Powets selection of an allocator unrelated to peak period demands is not at all 21 consistent with its findings that over 90% of these demand costs occur in the on peak peri. 22 If Nevada Power relly believed in the theoretical superiority of this allocator, then it certainly 23 should have applied it evenhandedly to all classes. Again, Nevada Powets proposal with 24 regard to this alloctor to WP rate classes is discriminatory, unjust and unreasonable. 25 26 Q. DO YOU HAVE A RECOMMENDATION TO MODIFY NEVADA POWER'S COST OF 27 SERVICE STUDY TO CORRECT THE WP SCHEDULES' DISTRIBUTION DEMAND 28 ALLOCATOR? ::ODMA\PCDOLRNODOIØ12081 Page 10 1 A. Yes. As I summarized in my opening te~imony, I recommend eiter of tw findings 2 by the Commission that would restore its prior findings. In this case the Commission should 3 order Nevada Power to be consistent in this regard with the POP allocator used for all non- 4 WP classes by ordering the pertinent POP WP rate class alloctors, as it did in Docket No. S 01-10001. My Exhibit DEP-1 contains the summary of my cost of service study that underiies 6 my remmenatin. 7 In the alternative, the Commission shuld order Nevada Power to use the kwh scled 8 allocator that the Company argued for and was authorized to use in Docket No. 03-10001; in 9 other words. assign costs base upon allocors used for the otherwse applicable classes. 10 i i Q. WOULD THIS LOWERING OF ALLOCATED COSTS TO THE WP SCHEDULES 12 RASE OTHER CLASES' RENUE REQUIREMENTS? 13 A. The retum to use of allocators previously use In prior dockets for WP schedules 14 would have a very minimal eff on some rate schedules, and no effec on others. The 15 maximum incrase to any single rate scedule fr this corrtion in WP demand allocators 16 is no more than .05 of 1%. 17 is Q. WHAT IS THE AFFECT ON WP BUNDLED RATES OF REVRTING BACK TO 19 THESE PREVIOUSLY AUTHORID ALLOCATORS? 20 A. While the impact of using my recommended alloctors is minimal for other schedules. 21 the impaq on the bundled WP rate scedules is large. Taken as a whole. this fix to the 22 distribution demand alloctors would reduce the rates for these classs by approximately 23 $600,000. This would change the Company conclusion that WP scedules be at the cap, to 24 no change over currnt rates. 25 If" 26 /III 27 /III 28 fill ::ODMA\PCOo\HLR0D01201 Page 11 1 IMPROVE DOS RATE CAlCULATION 2 3 Q. WHT IS THE ISSUE YOU RASE WITH RESPECT TO NEVADA POWER'S 4 CALCULATION OF THE PROPOSED DOS RATES? 5 A. Company winess Mr. Ghiglieri briefly outlines the development of DOS rates in his 6 testimony at Page 26, Lines 14-19. 7 If I may paraphrase to my own words wih respect to the distributon (nonrevenue 8 feeder) demand component: the DOS distributon rat component for the DOS water 9 pumping classes is the same as that developed for the correponding bundled water 10 pumping dass. Thus, the same noncolncident seted allocator used by the Company, and i i crticized by me in the preceding pages, pertains to the DOS rate as well. This is becuse 12 the DOS raes are not subject to a separate marginal cost study, but instead borred frm i 3 the bundled cot stdy. 14 15 Q. WHAT MODIFICATION DO YOU RECOMMEND BE ORDERED FOR THE , 16 DISTRIBUTION DEMAND DOS COMPONENT? 17 A. ' No additional modifcation to the DOS distribution is necessary if the Commission 18 requires Nevada Power in it bundled cost of servce study to retum to one of the tw prior 19 POP or kw scaled allocators. This corrion would as a matter of corse be picked up In 20 this component of respective WP DOS rates. 21 22 Q. WOULD THIS CHANGE REDUCE DOS RATES? 23 A. Minimally. I calculate the total savings from all six WP DOS classes to be 24 $12,OOO/year. But this corron would allow the design of bettr DOS rates, as I discss 2S next. 26 27 Q. WHAT RATE DESIGN MODIFICATION TO DOS RATES ARE YOU REQUESTING 28 BE MADE IN THESE PROCEEDINGS? ::ODMA~CDO\HLRODO\6120821 Page 12 i A. Consistent with the Company's findings in their cost of service study that its 2 distrbution demand rates are highly correlated with tirne-of-use ("TOU.), the Company 3 should implement a TaU-DOS demand charge, rather than Its proposed fixed racheted 4 demand or kw charge. 5 6 Q. PLEASE EXPLAN. 7 A. Nevada Power proposes to simply sum the facilities demand costs for DOS customers 8 with the distrbution demand charges that, again, have been shown to be infuence by 9 coincient peak loads. i 0 A better means to present customers wi meaningfl price signals would be to keep 11 the facilities' charges as proposed, but collect the TOU-related distnbution demand costs of 12 DOS customers through peak. mid, off and other perid per kw charges. as is done for 13 bundled tlme-of-use rate schedules. While collecting an equivalent amount of revenue 14 requirement, my proposal has the benefit of prvIding a further incentive to shif demand off 15 peak to lower cost peris, reducng additonal distnbuton investment for Nevada Power. 16 t 7 Q. HOW WOULD SUCH TOU DEMAND CHARGES BE CALCULATED FOR THE DOS 18 CLASES? i 9 A. All data nessary to compute these peak and off peak per kw charges are contained 20 in Nevada Powts cost of selVoe study. These rates are developed and shown In my 21 Exibit DEP-2. 22 These rates are based upon th time of use distnbution demand costs. developed for 23 the OAC classes. Due to the Interrptible provisions and rates of present bundled WP 24 classes, the OAC costs are more relevant, since DOS rates do not have an interrptible 25 feature. 26 27 Q. WOULD THESE TIME DIFFERENTIATED DOS DISTRIBUnON DEMAND RATES 28 ON EXHIBIT DEP..2 BE OF BENEFIT TO NEVADA POWER AND ITS CUSTOMERS? ::ODM\PCDOCL.DO2081 Page 13 1 A. Yes. These rates, beuse they are time differentiated. provide appropriate, cost- 2 based incentivs to move demand to mid and off peak periods. Accrding to Nevada 3 Power's cost study, significant amounts of new distribution investment could be avoided that 4 would otherwse be required to provide peak demand servce. These time of use rates 5 provie a more effcient usage of present and new distribution investment and all customers 6 save money. 7 8 Q. DOES THE PRESENT NEVADA POWER PROPOSAL TO CHARGE RATES FOR 9 THIS DISTRIBUTION DEMAND AS IF IT WERE NOT nME DIFFERENnATED PROVIDE 10 POOR PRICE SIGNAlS? 11 A. Yes. At present, water pumping operators are instructed to make all reasonable 12 effrt to shif its pumping operations away from Nevada Power's coincident system peak 13 period. These shifts, of course, allow energy bils to be managed, bu also invofve incurrng 14 signifcant distribution costs to keep demand shifed prmarily to off peak periods. 15 16 Q. DOES THE RATE DESIGN PROPOSED BY NEVADA POWER REMOVE SOME OF 17 THESE COST BENEFITS TO WP, DOS AND OTHER RETAIL CUSTOMER CLASSES? 18 A. Yes. Again. the Company's proposaf to charge a flt demand charge for these time 19 sensitive demand costs reduces water pumper incentives to manage its demand in the best 20 manner. 21 The time differentiated rates I provide in Exhibit DEP-2, while covering the demand 22 costs Incurred by the Company, promote effcient usage and conservation. 23 24 Q. WHAT ARE YOUR CONCLUSIONS"' 25 A. I have identified a major change made by th Company to the methodology it uses to 26 allocate distribution demand costs to bundled WP rate schedules. These changes were not 27 identifed or discussed anywere in the Copany's filing, and they contradict the rationale for 28 ::ODMA\PS\HLNODO\B12082\1 Page 14 ::ODV'CSLR0D01201 Page 15 AFIRTION I, Dennis E. Peseau, puruat to NAC 703.710 hereby afmi that the foregoing preard tesmony was prepared by me or under my diection and is corrt to the be of my knowledge. il~~ Dei Peseau Dated: ¡'/aft' 'i9¡1 ,;eq Attchment 1 Ok" 06-11022 Witnes: D.E. Peseau Page 1 of3 STATEMENT OF OCCUPATIONAL AND EDUCATIONAL HISTORY AND QUALIFICATIONS DENNIS E. PESEAU Dr. Peseau has conducted economic and financial studies for regulated Industries for the past twenty-eight years. In 1972, he was employed by Southern California Edison Company as Assciate Economic Analyst, and later as Economic Analyst. His responsibilites Included review of financial testimony. incremental cost studies, rate design, econometric estimation of demand elasticities and various areas in the field of energy and economic growth. Also, he was asked by Edison Electl Institute to study and evaluate several prominent energy models as part of the Ad Hoc Commitee on Economic Growth and Energy Pricing. From 1974 to 1978, Dr. Peseau was employed by the Public Utilty Commissioner of Oregon as Senior Economist. There he conducted a number of economic and financial studies and prepare testimony pertaining to public utilities. In 1978 Dr. Peseau established the Northwest offce of Z1nder Companies, Inc. He has since submitted testimony on economic and financial matters before state reulatory commissions in Alaska, California, Idaho. Marand. Minnesota, Montana, Nevada, Washington, Wyoming, the Distct of Columbia, the Bonneville Power Administration and the Public Utilties Board of Alberta on over one hundred occasions. He has conducted marginal cost and rate design studies and Attahment 1 Dkt. 06-11022 VV~ness: D.E. Peseau Page 20f3 prepared testimony on these matters in Alaska, California, Idaho, Maryand, Minnesota, Nevada, Oregon, Washington and in the District of Columbia. He has also conducted cost and rate studies regarding PURPA issues in the states of Alaska, California, Idaho. Montana, Nevada, New York, Washington, and Washington, D.C. Dr. Paseau holds B.A., M.A. and Ph.D. degrees in economics. He has co-authored a book in the field of industral organiztion entitled, §ize. Profits and Executive Compensation in the Large Corporation, which devotes a chapter to regulated industnes. Dr. Peseau has published articles in the following professional journals: Beviewof Economics and Statistics. Atlantic Economic Journal. Journal of Financial Management. and Journal of Regional Science. His articles have been read before the Econometric Society, the Western Economic Association, the Financial Management Association, the Regional Science Assodation and univrsities in the United Kingdom as we" as in the United States. He has guest lecture on marginal costing methods in seminars in New Jersy and California for the Center of Professional Advancement. He has also guest lecture on cost of capital for the public utility industr before the Pacific Coast Gas and Elecnc Association, and for the Executive Seminar at the Colgate Darden Graduate School of Business, University of Virginia. Attchment 1 Dkt. 06~11022 Witness: D.E. Pesu Page 3 013 Dr. Peseau and his firm have partcipated with and been members of the American Economic Association, the American Financial Asciation, the Western Economic Association, the Atlantic Economic Assciation and the Financial Management Assocition. He was formerly a member of the Staff Subcommittee on Economics of the National Association of Regulatory Utilty Commissioners. Dr. Peseau has been President of Utilty Resourcs. Inc. since 1985. Ta b l 1 : S U O f M i / l ~ . b y R a e i Ma F a c _ ~ i n 1 l ( 6 ~ C I S L i i d PA L t a i a . . i . i l . . ~ _ U 8 ) is , ! W 1 . 5 8 S5 , O Q 5 8 $1 3 6 1 4 7 $1 0 , 2 4 0 2 6 51 0 , 7 1 , _ 14 , 2 8 2 , 1 2 1 $5 . U 4 $0 $1 , 4 4 7 - 4 51 , I l $5 7 1 4 $1 9 , 6 1 9 $1 , 5 3 1 $7 5 4 $1 2 8 , 4 0 $1 3 , 4 2 1 $0 S1 7 . 4 1 5 S4 6 1 0 $0 Ui N o . -; 10 11 12 13 14 15 18 17 18 19 20 21 22 23 24 26 26 Z1 26 21 30 31 32æ 34 35 36 37 36 38 40 41 4243 It C l a n RS F a m l w fIRS GSLG 1 LG S i. P LG S T LG LG S P LGLG lGI. 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Pa g e 7 0 ( 2 6 Ta b l e 7 : M a r g i n a l D e m a n d R e w i e s S u b s t i o n Lin e No . Cl s s On Mid Of OC h e r To f 9 RS - M i A i F a m i l y 7, 3 , 6 8 1 71 8 . 6 2 2 17 7 10 2 , 5 1 8 8. 1 7 , 9 9 10 RS 33 , l 0 2 , 0 3 7 3. 0 6 , 2 9 7 68 1 39 2 4 1 4 37 , l , 4 0 11 RS - l 14 0 . 8 3 13 , 1 6 2 3 1, 9 4 0 15 5 , 1 8 7 12 OS 1, 8 1 2 , 8 0 7 15 8 , 0 5 42 30 , 2 3 9 1. 7 9 , 1 4 2 13 LG S . 1 11 . 3 , 0 8 2 1, 1 3 4 . 9 8 9 28 '8 9 , 5 5 12 , 7 1 7 , 9 1 0 14 LG S . 2 S 5, 7 . i . 6 3 58 , 8 16 2 10 6 , 9 8 ø, . 0 9 2 15 LG S - 2 P 13 9 . 2 14 , 5 6 4 2,4 4 9 15 8 , 2 8 16 LG S - Z T 17 LG S - 3 S 3.4 3 & . 0 5 36 2 , 7 2 0 99 63 , 2 0 1 3, 8 6 4 . 2 5 18 LG S o 3 3, 6 8 , 0 0 9 36 8 , 9 1 9 10 9 64 . 2 0 4, 1 1 8 , 2 4 5 19 LG S 0 3 T 20 LG S . X S ( n 1 ) 14 , 1 7 9 1, 5 2 0 0 14 5 15 , 8 4 21 LG S . X P ( n 1 ) 83 , 1 1 1 66 , 7 7 4 19 11 , 1 7 9 71 0 . 8 2 22 LG S X T 23 LG S 2 - W P S 37 , 4 1 1 4, 3 8 4 10 7 41 . 9 1 1 24 LG S 2 - W P P 14 , 7 4 4 1. 3 4 1 31 9 16 , 4 1 3 25 LG S 2 - w 26 LC i W P S 1, 5 0 5 2,0 7 1 1 41 3,6 1 8 27 LG S W P P 24 , 9 5 1 3, 8 8 9 4 35 29 . 2 0 1 28 LG S W P T 29 LG S . X . W P S 30 LG S X . W P P 31 LG S X - W P T 32 ss s 3S SS P 34 SS T 35 SL 45 , 2 7 1 10 , 9 5 13 90 57 , 1 4 6 sa RS i i 0 49 0 0 50 37 GS - P a l 0 14 8 0 1 14 9 38 A1 W P 39 OR S - l 40 OR S .. I OR S - L 42 OO S .f Ol G S . 1 44 45 TO T A l 87 . 9 0 3 . 9 4 ~3 4 , 2 7 7 10 5 7 4 96 6 , 7 3 7S A Ô § 8 6 8 Dl t l o n S y . . r g l ~ D i r r C o 75 , 4 0 5 , 8 6 8 1, 0 ~ ~ ~ 0 Ra l i l l C P 1 0 D e u t e d I n W P I I U o n d e Q l l i i : So u r o : " Ta b l 9 : C o m p u n o f A r u i i M e r g l n a l U I C o O e m n d R s ( p a 9 ~ , b ' s u b s w i t h i o x Wo r k p ø p e 3 ; l . i ; W e i g t P r b a b i l i t o f P e ( p a 2 3 ) . i e l l n f a r ( p a g e 2 3 ) . x Ta b l 2 : A n l i a S a l s a n d O J s t m e b y r a C l ( p g e 2 ) . (n l ) AI l o n o f e o f o L G S - X S a n d L G S X P . I V d ø b y 5 0 t o r e 1 t e l c u m e s p e d i b u t i o n . So m N e v d a W a f s r A u Do N o . 0 6 1 1 0 2 Ex h i t P I l o e p - Pa g e & o f 2 6 Ta b l 8 : M a t ì n a l D e n d R e u e s : N o R e n u e f e e d e r Li n a N o . Cl s s On Mi d Of Ol w To t a l 9 RS M ~ F a m i l y 18 , 5 1 8 , 2 7 1. 7 9 , 1 3 0 44 25 . 6 5 7 20 . 5 1 4 . 4 3 10 RS 84 , 1 2 5 , 9 7 7. 6 7 4 , 2 2 1, 6 5 98 , 4 4 2 92 . 7 8 3 , 8 1 9 11 RS - L 35 . 7 0 9 32 , 9 5 1 7 4, 8 5 6 38 8 , 2 5 12 GS 4, 0 3 7 , 7 9 7 39 , 6 9 2 10 6 76 . 7 0 7 4. 5 0 . 3 0 1 13 LG S . 1 28 5 2 3 , 5 2 9 2, 8 1 . 5 4 0 71 2 47 4 , 5 6 31 , 8 4 , 3 4 14 LG S - 2 $ 14 , 3 7 2 . 1 6 5 1, 7 4 , 1 2 0 38 0 26 6 , 6 2 7 16 , 1 1 3 . 2 9 15 LG S - 2 P 34 8 , 7 4 36 , 4 6 0 11 8,1 3 1 39 1 , 1 1 5 16 LG S 2 T 17 LG S - 3 S 8, 0 7 , 8 3 2 90 8 . 1 0 0 24 8 15 8 , 2 9, 6 7 4 , 4 1 0 18 LG S 9, 1 7 5 , 6 5 4 97 3 . 9 2 27 2 16 0 . 7 6 2 10 , 3 1 0 . 3 7 0 19 LG S - 3 T 20 LG S - X S l I i 1 ) 35 4 9 9 3. 6 0 1 36 3 39 . 6 7 0 21 LG S - X P l n 1 ) 1, 5 7 , 5 6 3 18 7 . 1 7 4 47 27 . 8 7 1. 7 9 2 . 7 7 2 22 LG S - X T 23 LG S 2 . w 93 , 6 1 10 . 9 8 11 26 10 4 . 9 2 7 24 LG S 2 . W P P 36 , 9 1 3 3. 3 7 8 1 79 41 . 9 2 25 LG S - Z - W P T 26 LG S - 3 W P S 3. 7 6 9 5. 1 8 4 4 10 1 9. 0 5 27 LG S - 3 W P P 62 4 6 7 9. 7 3 8 10 89 3 73 , 1 0 7 28 LG S - W P T 29 LG S - X - W P S 30 LG S X - W P P 31 LG S X . W P S2 SS S 33 SS P 34 SS T 35 SL 11 3 , 3 1 27 , 3 5 31 2, 2 2 14 3 . 0 6 36 Rs - i i l 0 12 3 0 1 12 4 37 GS - P a l 0 37 0 1 2 37 4 38 NN P 39 OR S M F 40 OR B 41 OR S L 42 OG S 43 OL G S - 1 44 45 TO T A L 17 0 , 0 0 . 1 7 8 16 0 3 . 1 0 7 3. 9 4 2, 4 1 8 , 4 3 18 8 , 7 8 4 , 8 DI & S l P i ' M 1 l U n D e n d C o 18 8 . 7 8 4 . 8 6 8 1. 0 ~ ~ So r c TI I 9 : C o p u t t i o n o f A n n u i i l M a r g U n i C o l i : D e a n d R e d ( P ' 9 ) . f o r n o e n u e f e e r w i 1 _ . . x Wo r p e r 3 : L o W e i g h l P r b a b i i t y o f P e k ( p g e 2 3 ) · r e s c a l i n g f a c t I P 8 2 3 ) , x Ta b l 2 : A n n u l i z S 8 1 e a n C u 8 1 b y r a i . C 1 s s ( p g e 2 ) . 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Pa g e 9 of 26 Su b 13 1 . 1 9 13 8 . 9 3 8. 1 3 % 0. 7 9 % 8. 9 2 % 12 . 4 0 1. 0 3 1. 5 13 . 9 6 1. 3 1 0. 9 6 0. 0 7 2. 3 3 0. 2 7 14 . 2 3 52 9 9 . 5 8 $7 5 , 4 0 5 , 8 6 15 . 2 14 . 9 7 No n R e v e n u e F f e r 32 6 . 4 8 34 5 . 7 5 8. 5 6 % 0. 7 9 % 9. 3 5 % 32 . 3 1 1. 5 2. 6 5 34 . 9 6 3. 5 2. 3 9 0. 1 1 5. 7 5 0. 6 6 35 . 6 2 52 9 9 . 5 6 $1 8 8 , 7 8 4 . 8 8 3B . 1 4 37 . 4 8 So c e : (n 1 ) P r o e d b y R e u r c P l a n n i n g , i l t o l p r o j e c c a o f b u i l d i n g a C o m b u s t o n T u r b i n e G e n e r r I n c l u d i n g A F U O C a n p l n n i n g r e e r v s o f 1 2 % . (n 2 ) W o r k p a p e r 3 : M a i n a l l n v e s t m n t I n L o a d - R e l a T r a n s m i s s i o n F a c i l i t i e s ( p e 1 8 ) . (n 3 ) W O f r 3 : M a r g i n a In v t m e n t I n l o d - R e l a t e D l b i b u o n S u b s t a U o n F a d l l t l ( p a 1 9 ) . (M ) W o i r 3 : M a r g i n l In v t m e n t I n L o d . R e a t e N o n R e v u e F e e l ' ( p a g e 2 0 ) . (n 5 ) 1 + W O l 1 a p e 1 3 : l o d i n g F a c t : G e n e r a P l a n t , M a t e l s a n d S u p p l i e s , a n d P r e p a ) ' n t s ( p 4 9 ) . (0 6 ) W o r p e 1 7 : A n u a l E c o m i c C a ~ n g C h a R e a t t o C a l n v l m e n t ( p e 5 4 ) , t r n s m l s l o n . s u b s t a n . a n d f a c i U l e s , r e p e c t v e l y . (n 7 ) W o r p e r 1 3 : L o d i n g F a d o f o A l G a n S O a l S e i t a n U n e p l n t T a x ( p e 4 7 ) . (0 8 ) W o r k p e r 6 : T r a m l a s l o O W E x e n e s p e k W o f S y s t e m P e a D e a n d ( p g e 2 8 ) · g e n e r 6 0 n c a p a d t y p m p o n o f t o t a t r n s m i s s i o n I n v e s t n t . (n 9 ) W 0 r p e r 6 : T r a m l s s o n O U A E x e s p e k W o f S y s t e m P e a l D e ( p g e 2 8 ) · t r n s m i s i o n p r o p o i t o n o f l o l a l t r n s m i I o n I n l l e n t . (n 1 0 ) W o r p e 7 : D l a b u l i n S u b s t a t i n O & M E x n s e s p e r k W o f D i s b u t i n P e k D e m a ( p e 3 1 ) . (n 1 1 ) W o r k p e 8 : F a d l l e s C h r g e s O & E x I 1 S p e k W ( p a e 3 4 ) . (n 1 2 ) 1 + W o r k p e 1 3 : l o a d i n g F a c t r f e A & G a n d S o c i S e c u r i t y a n U n e m l o t T a x e s ( p 4 7 ) . (n 1 3 ) W o r k a p e 1 3 : L o n g F a c l : G e r a l P l a t , M a l s a n d S u e s , a n P n ~ . n t s ( p 4 9 ) . (n 1 4 ) W O I a p e 1 6 : C a W o i n g C a l l F a d o a n D e r i v a t i o f R e R e r e f o r W o r n g C a p i t l F a c r ( p 5 3 ) . (n 1 5 ) W c i p a p e 5 : S y s t e m P e a k D e m n d L o s e . ( p a g e 2 6 ) . Ta b 9 : C o m p u n o f A n n u a M a r I n a l U n i t C o s t D e m a n R e l a t e Un e N o . 9 10 11 12 13 14 15 18 17 18 19 20 21 22 23 24 25 26 27 28 29 30 So e m N e l l d a W a C e r A u Do t N o . 0 6 1 1 0 2 Ex i b i t P e s D E . Pa e 1 0 0 1 2 6 Ta b l e 1 0 : M a i n a G e t i R e u e s Li n e N o . Cl a l S On Mi d Of Ot r TO l r 9 RS - M u l l F a m i l y 47 , 5 7 9 , 5 1 7 2, 9 3 3 , 8 7 9 0 0 50 , 5 1 3 , 9 6 10 RS 21 9 , 3 8 0 . 6 2 8 13 , 2 1 5 , 3 5 0 0 23 2 , 5 9 5 , 9 6 11 RS 91 8 , 4 1 9 59 , 5 6 6 0 0 97 6 , 0 4 12 GS 10 , 6 , 3 6 9 70 9 . 6 8 2 0 0 11 . 3 , 0 5 1 13 LG S . 1 74 , 5 , 3 6 5. 1 2 0 , 0 9 1 0 0 19 , 6 5 , 4 5 7 14 LG S . 2 S 37 . 1 3 0 , 7 6 3 2.6 2 1 . 5 8 2 0 0 39 , 7 5 2 , 3 4 4 15 lG S 2 P 90 0 . 7 0 9 63 . 1 8 5 0 0 96 3 , 8 9 16 LG S . 2 T 0 0 0 0 . 17 LG S - 3 22 , 1 1 1 , 1 5 9 1, 5 9 , 3 6 5 0 0 23 , 6 8 0 . 5 2 5 18 LG S - 3 23 . 6 3 1 . 6 5 1, 6 1 , 1 2 4 0 0 25 , 9 2 n 8 19 LG S - 3 4, 6 7 , 9 2 32 , 3 7 3 0 0 4. 9 9 , 3 0 1 20 LG S . X S 18 5 , 5 3 1 13 . 0 9 4 0 0 19 8 , 6 2 5 21 lG S . X P 8, 1 8 1 . 4 1 56 5 , 4 6 0 0 8. 7 4 6 . 7 0 22 LG S . X T 9, 1 8 , 4 5 66 l 5 9 5 0 0 10 , 2 8 3 , 5 9 23 LG S 2 . W P S 24 1 . 5 3 18 . 7 5 9 0 0 28 0 . 6 1 2 24 lG S . 2 . W P P 93 . 2 8 5. 9 8 1 0 0 99 1 25 lG S . 2 . . P T 0 0 0 0 28 lG S - 3 W P S 7, 7 2 2 8, 1 1 7 0 0 15 , 8 9 27 lG S - 3 W P P 15 7 . 0 1 2 15 , 6 7 5 0 0 17 2 , 6 8 7 28 LG S - 3 W P T 0 0 0 0 29 lG S . X . W P S 0 0 0 0 30 lG S . x . P P 0 0 0 0 31 lG S . X . W P 0 0 0 0 32 as s 0 0 0 0 33 SS P 0 0 0 0 34 SS T 0 0 0 0 35 SL 28 9 , 2 0 20 , 2 8 a 0 0 30 9 , 4 8 2 36 RS a l 0 0 0 0 37 Gs - l 0 0 0 0 38 NN P 0 0 0 0 39 OR F 0 0 0 0 40 OR 0 0 0 0 41 OR S - l 0 0 0 0 42 OG 0 0 0 0 43 0l G S 1 0 0 0 0 44 45 TO T A l 46 . 2 7 . 8 8 -2 9 , 5 . 6 -- - - 0 48 , Ø 8 æ S) P e k . . . . l n U I C e e o 48 9 . 8 8 3 , 5 3 1. 0 0 0 0 0 0 ~ ~ SO : = Wo i p e 2 : D e o n ~ M a r g i n l G e l l o n C i p a c l C o i ( p e g e 1 6 ) x Wo r p e 2 : L o a W e i g h t L o s o f L o P r o b a b i l i t y ( p 1 7 ) x r e s c i n g I a r ( p e 1 7 ) x Tl I l e 2 : A n u a i Z S a l e s a n C u s i b y r a C I ( p e 2 ) . l~.~*J-I. i III j I!!! =85: !! ~i' ~ II! 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CDc CD CJ ~!w Wo i t : M a r n a E n l l C c t i C o ~ Un t N o . 8 v a 0 . . . . $ / W H 10 A & I D f O ' h o & 11 l n C c d l ' S l i 12 Ç M h W O t I l Q C l p i l o V " l l o & 13 ~ ~ " f O W o i i i e a p M 14IIII 17,.,.20 2t 22 23:i 252l 'Z 28:i 30 31 32 33 34 353.37 38 38 40 41 42 43 44 4$41 474l.i SO 51 Su " " C J . . M k 2. 4 0 0. 5 1 5 1 0. S M 0. 0 4 0.t 1 5 3 lu m I ( Q n 11 5 . 7 1 0 96 . t 7 9 88 . 0 1 0 5 1l . S t6 . 7 I 95 . S 1 84 . 2 2 5 ". $ 3 95 . 4 3 0 au _ 80 . 1 2 1l , l M 94 . 1 4 2 80 , 8 $ 0 97 . 0 7 2 13 . 2 1. 3 7 10 2 , 8 2 1 1 84 . 3 0 0 t. 2 3 7 Sg m n w M ! d k 2A O 0. 5 1 5 6 0. 5 0. 0 4 D.t t S 3 Su t f N ! Ø2 . 6 1 1 83 . 0 4 1 82 . 1 1 0 5 82 . 1 m 82 82 . . 1 8 ll . l l 74 . 1 s e 82 . 3 7 81 . 1 l T Jl A 0 lI lt . 1 2 1 1 78 7 0 9 .3 . 1 9 7 el . 4 1 l i tE l 83 . 2 3 1 2 81 . 8 7 1Z 1 7U 4 $ 5 77 2 8 5 71 . 2 1 9 M. C 4 7 So N e v a w a A u o ñ OO e i N o . 0 $ 1 1 0 2 Ei ' - Q E . Pa g e 1 3 o f 2 1 Bi O f - f 2A 0. 5 1 5 OJ i 7 0. 0 4 2 0 0. 1 1 5 3 Su Q ! 55 2 5 3 1 55 . l T 1 4 55 . 7 5 3 54 . 2 51 . 7 3 SU 3 9 0 53 . 7 4 7 2 SO . l li M 3 53 . 8 S 52 . 0 1 1 7 64 . 2 8 1 53 . a 8 52 , 4 A SS . 0 6 1 5l 1 2 1. m 7 53 A 0 7 52 . l 1 1. 3 2 3 52 . 1 Ø ! 51 , 1 2 6 51 . 2 7 55 . 8 QI 2. 0 0 OJ 1 5 6 0. 1 0. 0 0. 1 1 5 3 s: 58 . & 7 7 lO 1 0 1 I¡ U 8 Z A 58 1 0 0 li $8 . 1 1 8 2 58 . 0 2 &U 7 8 S6 . a 57 , Ø 0 58 8 Z 58 . 8 7 3 58 . 1 1 7 5 58 B 1 ST . 3 5& . 8 8 5 1. 2 3 7 55 1 6 4 0 54 . 1 4 3 1. 3 5U 0 2 1 56 . 4 1 7 3 5U 1 7 0 80 , 0 1 8 1 SO . ~ 1 : L o w t i t . i g R u n n i n C c ( i n L i . ) ( p 1 4 ) + ( V 0 " " $ l W H x M G l a b V 8 0 & ) + l l - i : C c o f Fu S l + ( ( o & $ / ) + N I 0 & ' " $ l H x ( n 2 ) ) ) x c . W r i c . i t o v a i l 0 & . . ) x ~ ~ l s f o W o i l l C i l l (n t ) A " , o l l l l l l y M l I \ f i n a E i C G i a P R O M R u n . tn 1 W e i 1 3 : i . l l l n l l F ' f o M C h n c S o S i i 1 a n l l U n e m p l T a i ( p 4 T ) . (n 3 ) W a i 1 : i n C G t O f f u e s t ( i 1 5 ) . (1 ~ W o i , . : c . W o Q i " . - . D e . i o f ~ u . ~ e n t f C W C I C a r : l I ( p & 3 . (n 1 1 (n 2 1 (n i i (0 4 1 (0 4 1 Bm RS F a n , RSRS GS LG 1 LG LG P I.I.L. LG LG X S u; X P lG X T L. P S LG LG P T \. W P S LG P P L~ P T ~p s LG . . p p LG S P T SSSSSS saRs - l GS a l ANOR F OROR OGOL 1 $V M 85 . 3 8 2 5 77 . 5 2 2 77 . 4 8 97 . 2 7 4 " So u t h e r n N e W a t e r A u t h o r Do c k N o . 0 6 1 1 0 2 Ex h I b i t P e s u D E P - Pa e 1 4 of 26 Wo r k p a p e r 1 : L o W e i g h t M a i n a l R u n n i n g c o t s ( I n c l u d i n g L o s s e s ) 20 0 6 D o l S Un e N o . Ba Cls s Sl M m e r Q n e a k S u m M i d P e a k S u m m e r O f P e a Q! 9 RS - M u l t F a m a y 94 . 5 4 7 2 81 . 3 3 4 53 . 9 3 0 1 6 58 . 5 3 10 RS 94 . 8 5 81 . 7 1 9 3 6 54 . 5 4 7 6 4 58 . 8 8 6 11 RS - t 94 . 6 8 6 7 6 81 . 6 5 1 7 54 . 0 5 1 5 0 58 . 3 6 8 12 GS 94 . 2 4 3 1 5 80 . 8 0 5 8 52 . 8 8 1 1 4 57 . 7 7 6 7 1 13 LG S 1 94 . 4 2 9 2 81 . 2 1 7 0 2 53 . 7 4 9 1 58 . 2 2 5 8 14 LG S - 2 S 94 . 2 6 1 3 1 81 . 1 1 7 8 6 53 . 5 1 5 2 1 57 . 9 7 2 5 15 LG S - 2 P 92 . 8 9 8 7 8 79 . 6 7 4 0 2 52 . 4 2 3 58 . 7 2 7 4 3 16 LG S 85 . 2 1 4 5 8 72 . 8 3 49 . 4 9 8 58 . 0 4 1 1 17 LG S 94 . 2 1 9 2 1 81 . 0 1 2 9 8 53 . 1 3 0 57 . 5 7 2 0 0 18 LG 5 - P 92 . 9 4 5 5 0 79 . 8 9 4 9 6 52 . 3 3 1 7 0 56 . 5 7 8 6 2 19 LG 5 - T 89 3 0 2 0 0 17 . 0 8 6 50 . 7 5 7 9 4 55 . 2 20 LG S - X S 94 . 5 2 4 6 4 81 . 0 2 1 7 52 . 9 5 57 . 4 7 3 5 21 LG S - X P 92 . 8 1 8 8 0 79 . 8 0 3 3 52 . 4 6 4 2 8 56 . 7 9 3 7 3 22 LG S - X T 89 . 3 3 9 2 4 71 . 1 4 7 1 2 51 . 1 2 5 6 55 . 5 6 0 5 23 LG S - 2 - W P S 95 . 7 2 3 4 1 82 . 1 9 5 9 51 . 7 3 9 3 1 55 . 9 8 9 1 24 LG S - 2 - W P P 91 . 9 7 2 7 79 . 0 9 1 6 6 51 . 6 7 7 4 3 55 . 3 7 5 7 4 25 LG S - 2 - W P T 0. 0 ~ 0. 0 0 0 0 0. 0 0 0 0 0 0. 0 0 0 0 26 LG 8 - W P S 10 1 . 5 9 3 4 81 . 9 0 7 4 6 52 . 0 8 0 53 . 8 3 2 8 27 LG 8 - W P P 92 . 9 0 6 2 4 80 . 6 5 1 51 . 3 7 0 1 52 . 8 2 0 0 9 28 LG 5 W P T 0. 0 ~ 0. 0 ~ ~ 0. 0 0 0 0 0. 0 ~ 29 LG S X - W P S 30 LG S - X . W P P 31 LG S X . W P T 32 SS S 33 SS P 34 SS 35 SL 94 . 0 5 7 7 76 . 9 2 1 7 8 50 . 8 3 8 55 . 3 7 8 3 36 RS - a l 78 . 1 9 9 1 0 75 . 9 5 6 7 3 50 . 6 0 3 55 . 0 9 3 37 Gs - l 76 . 1 6 6 1 75 . 9 5 5 50 . 6 0 5 8 55 . 0 9 4 38 AI W P 39 OR S - M F 40 OR S 41 OR S L 42 OG S 43 OL G S - 1 44 SY S T E M 96 . 1 0 3 6 2 62 . 7 5 0 2 54 . 5 2 5 5 58 . 6 9 So u r c : Lo W e i g h t e M a i n a l E n e r C o ( f P R O M e D N n ) . So u t h e N e v d a W a t e r A u t o r i l y Do k e t N o . 0 6 1 1 0 2 2 Ex h i b i p e s e a u D E P - Pa g e 1 5 o f 26 Wo r k p a p e r 1 : I n c r e m e n t a C o s t o f F u e l s t c k Av e F u e l S t o c k f o r t h e Ye a r Y e a r ( S ' ( n 1 ) 20 0 6 1 3 . 5 1 5 . 9 3 8 9 10 11 12 13 Ne t G e n e r i o n P l u s Pu r c f M h ) ( n 2 ) 23 , 4 6 0 . 6 5 5 Cu r r n t C o s t o f F u e S t k (m i l s J W h ) ( 1 ) / ( 2 ) 0. 5 8 Us e i n t h e S t d y ( 2 0 0 7 $ ) : 0. 6 0 (n 1 ) c a l c l a t b y N P C ' s R e g u l a t r y A c c o u n t n g D e p a r t e n t a s o f J u n e 3 0 , 2 0 (n 2 ) P r o d e b y t h e D i r e o r o f E n e r g y S u p p l y O r g a n i a t i o n , a s o f J u n e 3 0 . 2 0 0 6 So u l l m N a v d a W a l e A u t t y Do No . 0 6 1 1 0 2 2 Ex P e D E Pa g e 1 6 of 26 Wo i p a r 2 : D e a t i o n o r M a r g i n a G e n r a o n C 8 C O t s 20 0 6 D o l l a r s Lm N o . 11 T O l I G e n e t i n C 8 C O t $ I . Y r e n 1 ) $8 . 1 7 1. 1 1 2 8 1. 0 9 3 1. 0 3 9 4 $ 9 5 8 9 $ 9 4 . 2 4 $ 8 9 . 5 7 1213 s e n d a r L o i s F a 14 P r r y l C F a d 15 T r a n s m i s s i L o F a c 16 17 s e d a W e l g d M a r g i n a G e i o n C 8 C o t ( M t 18 P r . . W e l g h M a r g l n 0 e C a p a c i e o ( $ l ) 19 T . . l u l o " W e l g h l i M a r i n a l O e l l n C a p a c i C o s t ( $ SO r c : (n 1 ) T a b l e 9 : C o p u t t i n o f A n n u M a r g i n a l U n i t C o D e m a R e l a t ( p a e 9 ) . So m N o v a l W i l A u i t Do N o . 0 6 1 1 0 2 ex l b n P e a u D E P - Pa g e 1 7 0 1 2 6 WG f p e r 2 : L o W e l d L o I I o I l l d P n b l i l l ( n 1 ) un N o . Ra c i s a Su m l D Q n M k SU m m e r W : f S U m m O ! l i k Q! l RS l l F e m l y 1. 3 9 0. 0 0. 0 ~ 0. ~ ~ 0 10 RS 1. 7 1 0 0 0. 1 1 1 5 6 0. ~ 0 0. 0 0 0 0 11 RS 1. 4 3 6 0. 1 1 3 ; 0. 0 0 0 0 0. 0 0 0 0 12 OS 1. 8 2 0. 1 0 2 1 3 0. 0 0. 0 13 LG S . l 1. 1 3 1 4 0. 1 0 3 0. 0 ~ 0. 0 ~ 14 LG S . 2 $ 1. 6 0 1 9 0. 0 9 1 0. 0 ~ 0. 0 15 LG S - 2 U2 1 l l 0. 9 1 3 0 O. O O 0, 0 ~ 16 LG S 0. 1 0 8 5 0. 0 ~ ~ 0, 0 ~ 0. 0 ~ 17 LG S 1. 3 2 5 7 0.0 1 1 4 7 7 0, ~ ~ 0 0. 0 ~ 18 LG S 1. 3 3 0. 0 9 8 5 0, 0 ~ 0. 0 ~ 11 1 LG & 1, 3 6 2 0.0 9 7 5 2 0. 0 ~ 0. 0 ~ 20 LG S X S 1. 3 1 0. 0 i 3 0 0. 0 ~ 0. 0 ~ 21 LG S 1. 1 3 2 8 0. 0 9 1 3 4 0. 0 ~ 0. 0 ~ 22 LG S X T 1. 3 1 7 0 0. 0 9 6 6 O. O D O, O D 23 LG S P S 1.8 1 5 9 1 0. 0 9 7 4 0. 0 0 0 0 0. 0 0 0 0 24 LG S 2 - 1.1 7 4 0 0 0, 0 4 2 4 8 0. 0 0 0 0 0. 0 0 0 0 2S LG S 2 - P T 0. 0 ~ 0. 0 ~ O. O O 0. 0 ~ 26 LG S 1, 0 6 Om S ! 1 0. 0 ~ 0. 0 ~ XT LG S 1. 2 5 7 4 2 O, O I 0, 0 ~ O. i x 28 LG S 0. 0 ~ 0. 0 ~ 0. 0 ~ 0. 0 ~ 21 LG S - - W P S 30 LG S - . W P P 31 LG S X - W P T 32 SS 33 SS 34 SS 35 SL 1. 2 7 " 6 0. 0 1 7 5 9 0. ~ ~ 0 0. 0 0 0 0 li e RS - l . 1 0, 0 0 0 0 0. 0 0 0 0 0. ~ ~ 0 0. 0 ~ 37 GS a l 0. 0 0 0 0 0. 0 ~ 0. 0 ~ O, O D 38 Al W 31 OR F 40 OR 41 OR 42 OG 43 OL G S 1 44 SY M 1. 1 8 0 0. 1 0 6 1 0. 0 ~ 0. 0 45-4 47..49 GO Ge t l 51 Re e c F i i r ( n 2 ) = 1, 1 1 0 0 8 So : (n 1 ) L o W e l L o e 0 1 L o i d P i o . l l A 1 1 o 1 1 ( " 1 0 0 0 ) . (n 2 s e t t o e q l h g e n e i l I d i h e y e p e k . u n l c o T a b 1 0 : M $ a l G e n e i a Re n u e s ( P l i i e 1 0 ) , Wo r t r 3 : M a l n a l l n v e l m e n t I n I . I s T r a i s s i F a c i l i t Lie No 9 10 11 12 13 '4 15 16 17 18 19 20 21 22 23 24 25 26 27 In v n t . . L o a d - R d T r a n s m i s i o F a c ì l i e 2 0 2 0 1 O . / n C o s t n t 2 0 7 D o a r s ( 0 0 ' $ ' . ( n 1 ) : Ad d i t i s C O S y t e P e k L o . 2 0 0 3 - 2 0 1 0 , ( M W ) , ( n 2 ) : To l a l M a r g i n a l l n v e s l m n t i n L o e l a l e T r a n s m l S $ F a c i l i t i p e k W I n C o s t n t 2 0 1 D o l a r s : Ye a r fi 1 e d L o a R e l t e J 1 s m ! H i o n ¡! W m m e n ' I n 2 0 7 D o l l a r s ( O O ) ( n U So u i t N e W a t e A u r i t y Do N o . 0 6 1 1 0 2 Ex t i t P e u D E p . Pa g e 1 8 0 ' 2 6 35 , 6 6 5 1, 6 6 3 21 5 . 6 1 Sy L o d ßr o ( M W ) 1, 6 6 3 So r c : (n 1 ) B a e d o n d a t s u p P i e d b y T r a n s m l s P l a n n l i i g a n d P l a n t A c c o n l l n g ( e i c u d e s S O r c o f s u p P y ) . (0 2 ) W o i 4 : D e a t i o f D i b u l l P e k L o a d s : H l s t l ( p a e 2 4 ) . a n W o r k 4 : D e r i t i o n O f D i s t b u t i n P e L o : P r e c e d ( p a 2 5 ) . Sy e m L g a d lM W ) ( n 2 ) 20 20 0 1 20 0 2 20 0 3 20 0 4 20 0 5 20 0 20 0 1 20 0 8 20 0 9 20 1 0 $2 9 . 7 9 3 $2 4 . 4 9 9 $1 1 3 , 9 5 0 $1 8 , 4 5 $3 , 1 9 6 $4 . 7 0 1 $6 1 , 6 0 $8 8 , 9 9 $9 1 . 8 4 2 $1 8 , 8 6 4. 6 6 1 6. 3 2 4 - 10 Y e a r l n v s b n e n t $3 5 8 , 6 5 So u t h e m N e v a d a W a t e r A u t h r i t y Do k e N o . 0 6 - 1 1 0 2 2 Ex b i P e s e u D E P - Pa g e 1 9 0 1 2 6 Wo r k a p e r 3 : M a r g i n a In v e s t m e n t i n L o a d - R e l a t e d D i u t S u b s t i F a c i l i t e s Un e N o . 9 10 11 12 In v e t m n t i n L o a d - e l a t e d S u b s i o n s , 2 0 0 1 - 2 0 1 0 , In C o n s t n t 2 0 0 7 D o l l a r s ( o o O ' s ) , ( n 1 ) : Ad d i t i o l ' t o D l s b u U o n P e k L o a d ( P r i m a r y ) , 2 0 0 0 . 2 0 1 0 ( M W ) , ( 0 2 ) : Ma r g i n a l In v e s t m e n t i n L o d - R e l a t e d S u b s t a t i o n s p e r k W o f D i s t r u b u t i o n L o d i n C o s t a n t 2 0 0 6 D o l l a r s : 20 5 . 4 4 1 U§ 13 1 . 1 9 f' r i m a r Q i s t b u o Q Lo a d G r o h a t Pr o j e c e d L o a d - R e l a t e d S u b s t i o n Su b s t i o s t M ) 13 YH In v e s e n t i n 2 0 7 D o l a r s ' C O O O ' s ) ( n 1 ) mi 14 15 20 0 16 20 0 1 ( 0 3 ) 17 20 0 2 ( 0 3 ) 18 20 0 3 ( n 3 ) I 4, 2 6 2 J( n 4 ) 19 20 0 4 ( 0 3 ) $2 9 , 6 1 9 20 20 0 5 ( n 3 ) $3 5 . 6 8 9 21 20 0 6 $2 4 , 2 2 9 22 20 0 7 $2 3 , 7 3 9 23 20 0 8 $3 6 . 9 7 4 24 20 0 9 $2 7 , 1 9 1 25 20 1 0 $2 8 , 0 0 0 I 5, 8 2 8 1( 0 4 ) 26 27 7 Y e a r I n v e s t m n t o a d G r o w $2 0 5 , 4 4 1 1, 5 6 SO u r c : (n 1 ) B a s e d o n d a t a s i p p J i e d b y D i s t b u n P l a n n i n g a n d P l a n t A c u n n g . (0 2 ) W o r k p a p e 4 : D e r i t i o f D i s t r b u t i n P e a k L o a d s : H I s t o r i c a l ( p a g e 2 4 ) , a n d W o r k p e r 4 : D e r i t i o n o f D l s t r b u t l o n P e a L o a d s : P r o j e c t e d ( p a g e 2 5 ) . (n 3 ) N e t a d d i t i o n s t o F E R C A l C 3 6 1 a n d 3 6 2 . P l u s f r o m P l a n t A c u n t i n g , s u b s t a t i n p o r t i o n o f F E R C A l C 3 6 0 . (0 4 ) I n 2 0 0 3 a n d 2 0 1 0 , 5 0 % o f t h l o a d s a t t b u t b l e t o t h e L G S - X S a n d L G 5 - X P a r r e m o v e 1 0 a c c m o d a t t h e c a l c l a t i o n o f t h e i r c u m e r s p d i s t r b u t o n . Fo r 2 0 1 O . t h o v l l g r o w t f r o m 2 0 t o 2 0 1 0 i s a p p l i e d t o L G S - X S a n d L G S X P d i s t r i b u i o n l o a d s w h i c h I s t h e n s u b t e d f r o m t h e f o t . WO l k p p e 3 : _ i n l n v e a 1 I n l o a N o I I F e e li n N o II 10tf 12 1r ~ I n L i - R l * d N c ~ _ F e e F d l i e , 2 0 2 0 1 0 , I n O o r i 2 0 0 7 D o a r s ( l I ) , ( n 1 ) : Ad n i o t o O I U l P e L o ( P a r y , 2 0 2 0 1 0 ( M W , ( n 2 ) : M8 l í n l l M I n ~ N o _ i : e r p e k W 0 1 D l b U l l o I n C o n l æ o 7 D o a n 13 1. -15 18 17 11 1 IL L 20 21 22 23 2A 25 28 Z1 28 2S 30 31 pI I ! J o P l l l f i ! I F i ç l ! . ~ i i N i i l l Ex d i n M e P r e c l . N o P e m n p r an d L l a n a I n B e a t S U D r D ! a D l I n y B ! 20 d c ! M I n y e n I n 2 0 7 P ! 2 0 C i i , , ! ! R 2 0 7 P a l a t o s ) Ym í l P O ! ! 8 ! ' C O s l ( ! ! ( 0 Q ) ( n 3 m £ 2020202O20202O 20 1 0 $o N e W a b l A i I t Do k 8 N a . 0 6 1 1 0 2 Ex b l P e e l l D E . Pi Z O o f 2 6 1l 1 1 , 2 t 1A 32 6 M Pr i ! M o i a !. d G m i t Su b l i ' ) ui 0. . , . . 58 2 ( 1 1 ) 1. 6 6 So : n1 : O I l o a d d i l f r m W o r p i 3 : N i n a i - m e n l l n L o I l N o R e v e n u e F e e " " , 7 ' Y ' T o l D I a n c N M - D e m a D r i e n I n v n t n2 O I s U l n S u m t f n W o r p ø 3 : M a I I 1 I t n t I r l . D i 1 0 S U 1 i F a _ n3 : N o n d r I I f r W D I p i 3 : l \ a r l n l l l ø n I n L . l i d N o n R _ i i F e e l l , 1 J ý T c t D l s t r l b n a n d N o n m a n D r i v I n v e s l l n4 : D i u U n a d l o s l e l o r e l l M I t a l o ! i e l l a n d n o n i d r Ì V n d 1 & l i i p l n5 S l b L o s f r W O l l a p e 3 : M a l n l n v e m e n t I n L o ~ e I O i b n S l F a c l i s p a 1 9 . 11 : I n 2 0 a n 2 0 1 0 , 5 0 0 I 1 h l o a t u t b l e 1 0 t h L G S X S I n L G S a r r e 1 0 a c 1 h i : k : l a l o f 1 l ~ C l i i 8 p 1 ! l c I b u t F o r 2 0 1 0 . t h I l I g r o 1 r 10 1 0 2 0 1 0 i a l I i f t o I . G S o a n L G 8 - X P \ l I o ' M \ $ t I ~ t o t i i o e t 8 n7 : 7 . ~ r R u l s 9 F e c I n v m e t i f r W o r 3 : M a i n a l I n v n t i n L o R ~ ~ n u F e 7 . y r F i i 8 ß M e t l n v p a e 2 1 . 15 3 , 9 2 1 29 , 1 1 1 1 1 25 88 , 3 0 16 1 . 1 6 6 31 , 6 l 20 . 5 7 7 Ø6 , 1 l 2 17 4 . 7 1 1 i 24 , 2 2 24 . 0 7 12 8 , 4 1 1 15 1 , 8 8 23 , 7 3 1 1 22 11 4 , 0 9 17 . , 3 3 38 , 9 7 4 24 . 0 2 11 3 , 3 16 3 0 8 27 , 1 9 1 22 7 4 11 3 . 4 2 8 16 1 m i 28 0 0 22 11 1 5 7 7. Y r i n v : F i i a n d N c i S . - 5 l 1 o D e a n d D r i v e n i. 7 . Y r , R U I I F a c l t I I l ( n 7 ) 7- V r 1 1 M : D e m a D r n N a S i Ø 17 4 , 0 1 26 7 8 6 51 1 , 2 5 5 7. y r L o d . l i l i o . & Ð n s ( M W SC N e a d W a t e A u t Do k e t N o . ~ 1 1 0 2 2 Ex b i t P e s e D E P ' Pa g e 21 0 1 2 6 ~ WO f 3 : M e i n a l l n v e a b n I n L o d - R e l a t d N o R e v e n e F e e e r s , 7 . Y ' F a c l I l l e s a n d M e t r l n v e l m e n t BJ~ 7- y r R u l e 9 Un N o . 20 1 0 ~ 1 = v C u Mm 7'' i M e t e Co t s l n 4 ) Fa c i l i t i e Un N o . 9 Cu ( 0 1 ) CU s t g S ( § ( 0 2 ) ~ Co l s ( n 3 ) In v e s t ~ II M & l n t 9 10 RS 30 0 0 22 8 , 6 8 71 5 8 .. . 4 5 $3 , 1 8 1 . 6 0 37 . 1 5 $2 , 9 9 , 0 1 0 10 11 RS 52 9 8 39 0 . 3 5 13 9 5 2 48 . 3 8 $6 , 1 4 9 . 6 6 11 3 5 . 5 0 $1 5 8 , 4 3 1 . 6 2 1 11 12 Rs - 15 2 12 3 29 32 1 . 2 $9 , 3 1 6 85 0 9 $2 4 7 , 8 9 1 1 12 13 GS 76 1 1 3 57 . 7 ' 1 . 18 3 8 85 . 8 $1 . 7 5 , 3 0 7 14 5 $2 . 7 7 1 , 9 7 0 13 14 LG S 1 31 + 4 23 . 4 1 2 80 31 9 . 4 3 $3 . 0 4 . 3 1 4 34 . 8 $2 . 6 4 3 . 9 9 14 15 lG S . 2 S 13 4 1, 0 1 5 32 14 3 . 9 1 $4 , 0 2 1 34 2 3 7 . 8 7 $1 1 , 1 2 7 , 3 0 8 15 16 LG S 2 P 45 23 22 49 1 1 . 6 0 $1 0 9 , 3 7 5 21 2 3 7 . 7 7 $4 , 2 3 1 18 17 LG S 2 T 1 1 0 54 0 1 . 7 8 $0 0. 0 0 $0 17 18 LG S 3 S 21 9 20 17 18 2 0 . 9 3 $2 . 5 63 . 7 0 $1 . 0 7 1 . 3 5 2 18 19 LG 3 P 94 75 19 49 2 4 . 0 1 $9 3 . 5 6 10 3 7 1 3 . 6 2 $1 . 9 7 0 . 5 5 9 19 20 LG 8 - T 14 10 4 53 5 4 . 2 0 $2 1 . 4 1 7 82 . 9 $3 . 2 9 0 , 2 1 6 20 21 LG S o X S 0 0 0 25 9 0 . 2 2 $0 0. 0 0 $0 21 22 LG S o X P 9 9 0 49 7 1 . 6 0 $0 38 7 . 7 5 $0 22 23 LG S o x r 6 5 1 54 0 1 . 7 8 $5 , 4 0 26 1 ' 1 . 3 3 $2 6 1 9 , 3 8 23 24 LG S . 2 - W P S 42 33 9 14 3 3 . 9 1 $1 2 . 9 0 35 . 9 5 $3 1 8 . 0 1 5 24 25 lG S . 2 . W P P 6 3 :3 49 7 1 . 6 0 $1 4 . 9 1 5 2D . 2 4 $6 1 , 9 3 3 25 28 LG S 2 - W P T 1 1 0 16 2 0 . 9 3 $0 0. 0 0 $0 26 27 LG S P S 10 9 1 49 2 4 . 0 1 $4 . 9 2 4 53 8 . 7 6 $5 , 5 7 9 27 28 LG S W P P 11 11 0 53 5 4 . 2 0 $0 74 6 2 . 3 8 SO 28 29 LG 8 - W P T 4 3 1 25 . 2 2 $2 , 5 9 0 0. 0 0 $0 29 3D LG S . X . W P S 0 0 0 49 7 1 . 6 0 $0 0. 0 0 $0 30 31 LG S - X - W P P 0 0 0 53 1 7 . 0 8 $0 0. 0 $0 31 32 LG S X . W P T 0 0 0 0. 0 0 $0 0. 0 0 $0 32 33 ss 0 0 0 0. 0 0 $0 63 2 0 . 7 0 $0 33 34 SS P 0 0 0 0. 0 0 $0 10 3 7 1 3 . 6 2 $0 34 35 SS T 12 9 41 . 1 3 SO 0. 0 0 $0 35 36 Sl 5 5 0 0. 0 0 SO 31 8 8 . 0 7 $0 36 37 RS 0 0 0 0. 0 0 $0 0. 0 0 $0 37 sa GS P a l 0 0 0 13 3 3 . 8 2 $0 0. 0 0 $0 38 39 AJ W P 0 0 19 1 . 8 $0 63 0 2 0 . 7 0 $0 39 40 OR F 16 2 98 64 19 2 . 6 $1 2 , 3 2 8 37 7 1 5 $2 4 . 1 3 8 40 41 OR S 23 6 0 94 1. 4 1 6 32 . 0 3 $4 7 , 4 1 6 11 3 5 . 5 0 $1 , 6 0 7 _ 41 42 OR S 0 0 0 19 2 . 1 9 $0 85 4 . 0 9 $0 42 43 OG S 20 12 8 38 1 . 2 1 $3 . ~ 14 5 6 . 0 3 $1 1 . 1 1 43 44 Ol G S o 1 22 2 20 0. 0 0 $0 34 . 8 8 $6 . 8 1 8 44 45 $1 5 . 7 9 , 6 $2 , 7 8 5 , 5 45 46 46 01 : 2 0 1 0 e u t o p r o a n s p n : e d b y L o d F o r c a s t a i u s e d i l B u d g e ' f o r e s t n2 : 2 0 0 3 c u t o c o o l s o b 1 a i n f r c o m p a n y f t o a n e r e f o r 1 2 / 3 1 1 2 0 0 03 : W o r a p e r 9 : M e t R e l a t e d O & E x n s a s b y C u s t e r C l 04 : W o r a p r 1 1 : D e t i o f M a r g i n a l F a c l l C h a r g so N e W _ , t Do N o . 0 & 1 1 0 2 Ei l P e c e - Pa g e 22 of 26 Wa d 3 ; M a i I l n v I n ~ N O r u " - 7 - y T o t l D i a n N o D r l n Un a .i 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 3S 37 38 39 40 41 42 43 44 "5 Di s t n b u P l n t A d t i . e x l u d i n g M e t e r s a n d L i h t . 2 0 0 7 $ No n d r e l a t e D i s t r t i n A d d l n a 2 0 7 $ Re Co Ad i l ! Re Co c t YM A d d i t o n t n n In d e f n 2 ) ~ Ye a r ~ In d e x f o 2 \ 20 15 4 6 5 7 2 5 4 80 . 8 8 19 1 2 1 6 1 6 5 20 0 3 $1 U ì 8 4 . 8 3 5 80 . 8 8 20 $1 3 2 . 9 6 3 , 3 8 86 . 3 8 $1 5 3 . 9 2 . 7 6 9 20 $2 2 , 4 5 , 5 6 3 86 . 3 8 20 $1 4 1 . 6 7 . 2 5 5 92 . 3 7 $1 5 3 , 1 5 8 , 4 1 20 0 5 $1 9 . 0 0 , 2 4 4 92 . 3 7 20 $1 7 2 7 9 1 , 7 9 1 98 9 0 $1 7 . . . 7 1 4 . 9 5 20 0 8 ( n 3 ) $2 3 , 8 1 0 , 7 0 9 98 . 0 20 7 $1 5 9 . 8 6 , 9 0 4 10 0 . 0 0 $1 5 9 , 8 6 , 9 0 20 0 7 ( n 3 ) 52 2 , 0 2 9 , 1 0 8 10 0 . 0 0 20 $1 7 6 , 1 6 8 , 6 0 2 10 1 . 0 5 $1 7 " . 3 3 , 0 7 8 20 0 B ( n 3 ) $2 4 , 2 6 . 3 3 10 1 . 0 5 20 $1 6 6 , 2 1 5 . 0 3 8 10 1 . 9 1 $1 6 3 , 0 9 , 8 20 0 ( n 3 ) $2 2 . 9 0 . 4 3 10 1 . 9 1 20 1 0 $1 6 7 , 6 1 2 . 4 4 2 10 3 . 5 4 $1 6 1 . 8 7 . 4 5 3 20 1 0 ( n 3 ) $2 3 , 9 6 . 9 9 10 3 . 5 4 Po r t N o e m a n d R e l t e d D i s o n A d d i l l s t o D i s 1 b u t A d i t E x l u d n g M e e r s a n d U g h t l n = 7- y r T o l a A d i t i . $ 1 , 1 4 0 . 9 6 , 5 1 3 Ad l l O l a1 $2 1 . 8 6 5 , 3 6 3 $2 5 , 9 4 , 9 $2 0 . 5 7 6 , . $2 4 . 0 7 5 . 7 2 $2 2 . 0 2 9 . 1 0 8 $2 4 . 0 2 3 , 9 8 $2 2 , 4 7 4 , 2 1 $2 . 3 0 6 . 9 8 9 13 . 7 8 % 7- y T o l A d s ( O O s ) = 7- y T o t l A d d i o n . ( N o n - e m a n d . 0 0 0 ' 8 ) = 7- y T o t l A d d i t s ( N o n - D e m a ) . $ 1 6 1 , 4 8 1 , 0 4 2 $1 6 1 . 4 8 1 $1 . 1 4 0 . 9 6 3 n1 : " E R e F o r m 1 ( 2 3 . 2 0 0 5 ) p a g e 2 0 l i n 7 5 m i u s l i n e 7 0 , 7 1 . 7 2 , a n 7 3 , F o r a d d l l p r i d b y D 1 t r n P l a n n i n g D e 02 : W o r p e r 1 8 : P r n t V a l u I n d i c e n3 : F o r c s t N o a n d D i t i n A d d i t i o n s b a s e o n a v e g e p e n t g e 0 1 hi t o c a n o n - e m a n a d l l t o t o l d i s t i t l n o a d o n s ( 1 3 . 7 8 % ) Li n e N2 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 Z7 28 29 30 31 32 33 34 3S 36 37 38 39 40 41 42 43 44 45 .. tit l lii~ ~- R~8 i &~iii III i lIfiiilil.llllligii II 1.1.1 j - ~ I..d............. dd ... d ¡ i ~l Illlllllllllillll ii llI I jl l IIiP .81· ¡ Ii! lè5 ~l .1~ ~llll§l~l~lll~ll ll ~lI l ll ii Ii i if ~.t:tt:lt il~ll l !i~i~~~~¡~~~ll~illll¡lii5ìï~äl~llg§~1 illiil i illi~¡ II II.,I!Il ~ l I 1-H J lÎIi JIi ..ifi ~~ r.sæ=t!l!:!~~t::!liIHii:R~IUll:IUli~IHl~=iJli;:R~~;!:n::S~'!W~~i~ r" - - ~iiodd ¡ læ~ l~°1.- Wo r p e r 4 : D e r i t i o f D i s u t i o n P e a k L o a d s : H i s t o r i Li n e N o . 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 Ma r g i n a l D e m n d L o s F a c t r s : Ye a r 20 0 0 20 1 20 2 20 0 3 20 0 4 20 0 5 15 9 . 1 17 1 1 17 0 . 2 16 16 9 . 0 17 6 . 0 tr a n s s i o n - Pr i m a r y - To t a l Tr a n s m i s s i o n L o d s ( M W , ( 0 2 ) To t l W i l h lo s e s Pr i m a r y L o d s ( M W ) , ( 0 2 ) To t a l W l i To t a l L o s s 16 5 . 4 17 7 8 17 6 . 9 16 9 . 4 17 5 . 7 18 2 . 9 0. 0 3 9 ( n 1 ) 0. 0 9 3 6 ( n 1 ) 2ß . 7 2 8 7 . 3 25 7 . 0 2 8 1 . 1 27 7 . 5 3 0 3 . 5 28 3 . 0 3 0 9 . 5 29 1 . 0 3 1 8 . 2 32 9 . 0 3 5 9 . 8 So u r c : (n 1 ) W o i t p a p e r 5 : S y s t e m P e a k D e m a n d L o s s ( p a g e 2 6 ) . (0 2 ) P r o v i d e b y R e u r c e P l a n n i n g . (n 3 ) S y s L o d - ( M r e T r a n s m i s i o n L o a d a d j u s f o r l o s t o G e n e r t o r ) = D i s t r b u t i o n l o a d à t G e n e r a t o . Di s t r u t i n L o d a t S u b s t a t i o n = D i s t r b u t i o n L o a d a t G e n e r a t o r r e u c e d b y l o s s e s t o S u b s t i o n . Ye a r 20 0 0 20 0 1 20 0 2 20 0 3 20 0 4 20 0 5 Sy s e m P e a k L o a d s ( M W ) , ( n 2 ) We a t h r Ac l a l N o r l i z e So r n N e v a a W a t e r A u t h r i Do c k e t N o . 0 8 - 1 1 0 2 2 ex h i b i t P e s e a u D E P . Pa g e 24 of 26 Su b s t a t i o n to P r i m a r y L o a d 1. 0 5 2 Di s t r i b u t i o n P e a k L o a d s ( M W U A t G e n e r a t i o n ) , ( n 3 ) D i s t r i b u t i o n P e a k L o a d s at P r i m a r y a t S e o o n d a r y a t S u b s t a t i o n 4, 3 1 1 4, 4 1 2 4, 6 1 1 4, 8 0 8 4, 9 6 5. 5 6 3 4, 2 9 5 4, 3 2 2 4, 5 2 6 4, 4. 9 1 1 5. 2 3 4, 1 3 0 4, 1 4 4 4, 3 4 9 4, 4 9 2 4, 7 3 5 5, 0 5 0 3, 8 4 2 3, 8 6 3 4, 0 4 6 4, 1 8 2 4, 4 1 1 4. 6 9 3. 9 7 3 3, 9 8 4. 1 8 4 4, 3 2 1 4. 5 5 6 4. 8 5 9 Wo t p e r 4 : D e r i v a o f D i s t b u P e a k L o a : P r o j e li n e No . 9 10 11 12 13 14 15 16 17 18 19 20 21 Ma i g l n a l D e m a l o s s F i i c : Tr a n s m i i o n - Pr m a r y - Tr a n s i s s i o n L o d s ( J ) . ( n 2 ) To t a l Wi t Ye a r T o t a l o e s 20 20 7 20 8 20 9 20 1 0 16 7 . 0 17 0 . 17 5 . 0 18 4 . 0 18 8 . 0 Pr i m a r y L o a d s ( M W ) . ( n 2 ) To t l W i l h To 1 a 1 L o s 11 3 . 6 17 6 . 7 18 1 . 9 19 1 . 2 19 5 . 4 33 5 . 7 34 1 . 2 35 2 . 2 37 4 . 0 38 3 . 9 30 7 . 0 31 2 . 0 32 2 . 0 34 2 . 0 35 1 . 0 So u t c : (n 1 ) W o r k p e r 5 : S y e m P e a k D e m a n d L o s ( p a e 2 6 ) . (n 2 ) P r o v i d e d b y R e u r c P l a M i n g . (n 3 ) D i s t r b u L o a d a t S u b s t a t i o n " D i s t r b u t n l o a d a t G e n e r a t o r r e d u c e d b y l o s s e s t o S u b s t a t i o n . 0. 0 3 9 ( n 1 ) 0. 0 9 3 6 ( n 1 ) So N e a W a t e r A u t h Do c k e t N o . 0 6 1 1 0 2 Ex h i b i t P e s e a u D E P . Pi i g e 2 5 o f 2 6 Wi t h L o e s _ ( A t G e n e r a t o r ) D i s t r b u t n L o d Pe a k l o a s ( M W ) . ( n 2 ) a t S u b s t a t i o n ( n 3 ) Sy t e P r i S e c n d r y 58 3 5 . 4 9 4 19 1 5 . 6 8 21 3 5 . 8 9 8 22 7 6 , 1 2 5 19 9 6 . 3 2 5. 3 2 0 5, 5 0 5, 7 1 6 5. 9 3 4 6, 1 2 9 4, 9 8 5 5, 1 6 7 5, 3 6 4 5, 5 6 0 5, 7 4 5 5. 1 1 9 5, 3 0 5. 4 9 9 5, 1 0 9 5, 8 9 6 So u l h e r n N e v a d a W a t e r A u t h o r i t y DO C e t N o . 0 6 - 1 1 0 2 2 Ex h i b i t P e s a u D E P . Pa g e 26 of 2 6 WO r K p a p e r 5 : S y s t e m P e a k D e m a n d L o s s e s Li n e N o . g S Y S T E M P E A K D E M A N D L O S S E S I N P E R C E N T : 10 11 D E M A N D L O S S E S D I S A G G R E G A T I O N : 12 5. 8 8 2 % 13 V o l t a g e L e v l 1. 4 D i s t r i b u t i o n S e c o n d a : 15 D i s t r i b u t o n P r i m a r y : 16 T r a n s m i s s i o n : Av e r a g e D e m a n d Lo s s e s 1. 1 1 2 8 0 1. 0 9 3 6 1. 0 3 9 3 9 So u r c : NP C e n g i n e e r i n g p e r s o n n e l s u p p l i e d s y s t e m p e a k d e m a n d l o s s s , a n d e s i m a t e s o f U 1 e s e l o s s e s d i s a g g r e g a t e d by v o l t a g e l e v e l a n d f i x e d a n d v a a b l e c o m p o n e n t s , u s e d t o c a l c u l a t e a v e r a g e d e m a n d l o s e s . . . , , SNWA Pi Time of Use OOS Rate lo WP Schdules Base upon Otle AppDcable Classs DiSbbuton Time Diffntte Coat Based Rates Line No. Co Compone:-8- lGS-2S 10 Distbuton SelCs 11 C\ Cl (pe Cust per Mo.) 12 FscCh (pelcW, peMo.) 13 Prima(perkW, peMo,) 14 On Pea 15 Mid Pek16 OfPNk18 OUer 19 TotlOisbbuton ServsClum: LGS-2P 23 OislrbUlon S~S 24 Cu Ch (per Ous, pe Mo.) 25 FacChg(pekW.perMo.) 26 Priary (per kW, perMo.) 27 On Peak 28 Mid Peak 29 Of Pea30 0l 31 Tol Dibuton S8iC8$ Checksum: LGS-3S 36 Olatbuton Ses 37 CcCl(peCU peMo.) 38 Fac Chg (pe kW. pe Mo.) 39 Prry (per kW. pe Mo.) 40 OnPeelc41 Mid Pek 42 OIfPeak43 Oll 44 ,. ola' Dislrbuton S8rva Chedm: lG5-P 49 Oilt Seiv 50 Cu Ch (pe cust per Mo.) 51 FacChg (perkW. peMo.) 52 Prfma (per leW, pe Mo.) 53 On Peek54 MldPe55 OIfPeak56 Oter 57 Tota DlsbUln SÐces Checksum: 2,06,211 Marginl Coat Baed RasalClssRalesatClsCOS Revenue Marginal Co Renue Ba Rev-0--E--F--G- $2,478 $178.88 $1.92 $138,94 $4,282 $0.61 $3..$0.7 $20,113 $10.16 S 15,622 $7.89 $2.063 $1.01 $1.603 $0.79 $373 $0.11 $290 $0.08 $2930 $22766 $2930 $22.766 $91 $295,04 $71 $229.16 $59 $0.30 $46 $0.23 $48 $10.25 $379 $7,96 $51 $0.97 $40 $0,75 $9 $0,08 $7 $0.06 $698 $542 $698 $542 $468 $185.02 $364 $14372 $1.441 $0.38 $1.119 $0,29 12.04 $10.73 $9.357 $8.34 $1.271 $1.10 $987 $0,86 S 221 $0,11 $172 $0,09 $15.448 $11.99 $15.448 $11.99 $316 $29,48 $246 $ 227.97 $1.009 $0.25 $784 $0.19 $12,841 $11.06 $9.974 $8.59 $1,363 $1,14 $1.059 $0.88 $225 $0.11 $115 $0.8 $15,754 $12,23 $'15.754 $12.238 Bllling Uni-- 13,852 7.029.526 1,98,010 2,034,133 3.494.008 310 196.974 47.57 62,53 108.69 2,532 3,840.335 1.122,311 1.153.534 1.973.457 1,078 4,05.861 1,160,551 1.200.08 Line No_ Pese - DEP.2 10 11 12 13 14 15 16 18 19 23 24 25 26 27 28 29 30 31 36 37 38 39 40 41 42 43 44 49 50 51 52 53 54 55 56 57 '4 . ... 2 3 4 5 6 7 8 9 'f 10~o~o o C' ..11:i $ 0...t" 'I :: 0\12§ v. 00 Q li 13 -I ~ tiZ 14oli 15~_.~o:;Qo~ i: ~.. 5 16 IJ Ql å~17~t"üot" 7ü t"18:: 19 20 21 22 23 24 25 26 27 28 PROOF OF SERVICE I hereby certify that I mailed the foregoing Direct Testimony of Dennis E. Peseau in Phase TV Cost of Serice and Rate Design in Dkt. 06-11022 on behalf of the Southern Nevada Water Authority via electronic mail and by delivering to the U.S. Post Offce copies thereof~ properly addressed for mailng to the following persns and entities: Nancy Barker Nevada Power Compay 6226 W. Sahar Ave. MS 3A Las Vegas, NY 89146 nbarker(fiievp.com Marisa Cardena, Rate Analyst Nevada Power Compay 6100 Neil Road Reno, NV 89511 mcardenasiIspoc.com Eric Witkoski, Consumer Advocate Bureau of Consumer Protection Oflce ofihe Attorney General 555 E. Washington, #3900 Las Vegas, NV 8910 i epwiikosíaiag.state .nv .us Charles Radal, Business Manager IBEW Local 396 3520 Boulder Highway Las Vegas, NV 89120 Mark Russell, Esq. Mirage Hotel and Casino 3400 Las Vegas Blvd. South Las Vegas, NV 89109 ml11sselli£mirage.eom Donald Brookhyser, Esq. Alcantar & Kah LLP 1300 SW Fift Ave., Ste. 1750 Portland, OR 97201 debúòa-kJaw.eom Dan Waite, Esq. Beckley Singleton, Chtd. 530 Las Vegas Blvd. South Las Vegas, NV 89101 dwaite(ã)beckleylaw.com ::ODM¡\\PCDS\HI.RNOOO\612179\ I Jan Cohen, Esq. Public Utilties Commission of Nevada 101 Convention Center Drive, Suite 250 Las Vegas, NV 89109 jcohen~puc.state.nv .us Alaina Burtcnshaw Public Utilties Commission of Nevada 101 Convention Center Dnve, Suiie 250 Las Vegas, NV 89109 aburens~puc.staic.nv.us Phil Wiliamson Bureau of Consumer Protection Offce of the Attorney General 100 N. Carson Streel Carson City, NY 89701-4717 pjwilliaßiag.stte. nv. us Francis J. Mortn, Esq. IBEW )).0. Box 370955 Las Vegas, NV 89137 Martha J. Ashcratì Lewis and Roca LLP 3993 Howard Hughes Parkway, SuIle 600 Las Vegas, NV 89169 MAshcrafi'i LR Law.com D. George The Kroger Co. 1014 Vine St., 0-07 Cincinnaii, OH 45202 dgeorgetq1kroger.com Dale Swan Exeter Associates, Inc. 5565 Sterrett Pluec, Suite 3 i 0 Columbia, MD 21044 dswan!âexeterassociates.coni Page 1 . i I ~ 7 8 9 18 ioON,. 11 =i~ lui~ 12 Ui 13 l.l~ 14 ~eÕ 15 ~iI 16!tO 17 .;r- 18 i: 19 20 21 22 23 24 25 26 27 28 1 Kur Boehm, Esq. 2 Michael Kur Esq. Boelu, Kurz & Lowr3 36 E. Seventh St., Ste. 1510 4 Cincinnati, OR 45202 kboehm(gBKLlawfnn.com 5 mkIaw(ßol.com 6 Dated this 19t day of Marh, 2007. ::QDMA\PDO\HLRI21791 Page 2 Lawrce A. Gollomp Assistant Gener Counel Lot H. Cooke, Attorney U.S. Deparent of Ener 1000 hidepdene Avenue, SW Wasinon, DC 20685 Lawrce.GolIompCW.doe lot.cookW?.dod.gov ¿~ An employee of HAL LANE PEEK DENNISON AND HOWARD HALE LANE ATTORNEYS AT LAW 1n Ea WiBiam Sin I Suile 200 I Cii Cil. Nevada 8910 I 'felcpe (175) 6l I Faciuule tl1S) 684-6001 WW.belilll.L'11I September 13, 2006 Crystal Jackson Commission Secreta I 150 E. Wilia Stret Caron City, NV 89701 RE: SNWA DIRECT TESTIMONY DOCKET NO. 06-06051 Dear Ms. Jackson: Please accept for filing the enclosed original and nine copies of the Direct Testimony of Dennis Peseau on behalf of SNW A in Docket No. 06.0605 i . Should you have any questions regarding ths filing, please contact me at (775) 684-6000. Sincerely, 5/Md~ Fred Schmidt, Esq. FJS:taw Enclosures cc: Paries of Record oCl (/') eJ. HALE LAN": PEEK DENNISON AND HOWARD RENO OFFICE: 5441 Kiot Lan I Seçond Floo I Ri:o. Neva 895111 Ph (715) 327-3000 1 Facsimile (115) 786-6179 LAS VEGAS OFFICE: 3930 Howad H"ghes Piay I Fourh Floor I Li Vegas, Neva 891691 /'one (702) 222-2S00 I Facshnìlc (702) 365-6940 ::ODMA\PDOSIHLRNODOS\566781\1 '.,."- ~~~f. n -.-~~."-. " ',\:i~i:=,,:,.::0 :".;:~:..~....':";1."CO"'-"-: ~-;-_..--...(/,=:~ .'~'(".%-. t.. -Q:¡t:-,N 1 2 3 4 5 6 7 8 9 10 11 Q. 12 A. 13 14 15 Q. 16 A. 17 18 19 Q. 20 A. 21 22 23 Q. 24 25 A. 26 27 Q. 28 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA Docket No. 06-06051 Direct Testimony of Dennis E. Peseau "l ". Ct '~':~ en :':E:en :,-,rr .:;: i:";-:.!;:. ~'r-rt c..:..=i.n(ì;;~ -0 :.'.J)~:i "1"'"1;~'~O~":..\0¡;..:: !:i:lN"~~."0%""Ii on behalf of Southern Nevada Water Authority PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. My name is Dennis E. Peseau. My business address is 1500 Libert Street S.E., Suite 250, Salem, Oregon 97302. BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED? , am President of Utility Resources, Inc. The firm consults on a number of economic, financial, and engineering matters for various private and public entities. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? I am testifying on behalf of the Southern Nevada Water Authority ("SNWA1') and its constituent members. DOES ATTACHMENT 1 ACCURATELY DESCRIBE YOUR BACKGROUND AND EXPERIENCE? Yes. WHAT IS THE PURPOSE OF YOUR TESTIMONY? ::OOM\PCOOCSLRNOOOCS\56656\1 Page 1 1 A. 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Q. 24 A. 25 26 27 28 The purpose of my testimony is to express SNWA's general but cautionary support for Nevada Power Company's ("Nevada Power" or "the Company") filed Integrated Resource Plan ("IRP") in the instant docket. The urge for caution that I express below derives from the enormit of the Company's plan, the very infant or "greenfield" nature of the bulk of the generation and transmission request, and the capital intensiveness and the long-lead times required to determine the feasibilty of the IRP. In this regard, I propose that the Commission and parties provide sufficient support and endorsement for the beginning elements of Nevada Powers filed IRP, but stop short of the numerous and, in my opinion. premature granting of complete financial assurances requested by the Company. Specifically. I recommend that the Commission rule as premature the Company's request for Critical Facilities designation and instead approve up to $300 milion in the requested preliminary EEC and Intertie studies, to be treated under normal AFUDC accounting (no CWIP) and set a procedure for eventually issuing a final ruling on Critical Facilities status and related accounting issues at a later date as the project develops or not. In the alternative! I recommend that the Commission deny Nevada Power's request for Critical Facilities designation for the Ely Energy Center ("EEC") and the 500kV Nort/South Intertie ("Intertie") unless and until such time as the costs, budget, timing, and rates resulting from completing Phase One can be shown to be reasonable, not unduly burdensome, and in the public interest. i discuss these cost and financial issues below. WHAT ARE SNWA'S PRIMARY INTERESTS IN THESE PROCEEDINGS? As the principal water purveyor for the burgeoning southern Nevada economy, the SNWA has enormous interests in the outcome of this resource plan case, both as a retail electric customer (for DOS and vertically integrated services) and as a transmission customer. The outcome of these and similar proceedings could have a ::ODM\PCDOCS\HLRNODOCS\556\1 Page 2 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Q. 22 23 24 A. 25 26 27 28 significant impact on the abilty of the SNWA to continue to economically serve the water needs of southern Nevada. The SNWA has underway its own water importtion plan, requiring it to be served with energy in eastern Nevada as far north as White Pine County. Regardless of the eventual shape of its water importation plan, the SNWA must protect its customers and control its water pumping costs by developing the best possible transmission and generation options to accommodate its needs. It is critical for SNWA to have the transmission infrastructure to serve its importation plan in place when water pumping needs commence. To this end the SNWA has been developing a trànsmission plan to meet the needs of the water pumping requirements associated with its water importation plan. When the SNWA became aware of Nevada Power's plans last winter to construct proposed 500kV lines in the same general area as that planned by the SNWA for its water importation project, the SNWA initiated meetings with Nevada Power to discuss possible common interests. At that time, SNWA had already identified electncal transmission needs in Clark, Lincoln, and White Pine Counties as part of its proposed water importation project. One topic of discussion was the potential to jointly share ownership of the Nevada Power proposed transmission expansion described in this filing. DOES THERE APPEAR TO BE ENOUGH SIMILARITY IN THE TIMING, CERTAINTY, AND ENGINEERING OF THE INTERTIE TO EXPECT THAT A JOINT OWNERSHIP ARRANGEMENT WOULD MEET SNWA'S CRITICAL TIME PATH? While there are some similarities in timing and location, it is not clear that. Nevada Powets Intertie wil meet the electrical needs of SNWA. Most of SNWA's needs in eastern Nevada require a smaller transmission size. The SNWA has, by necessity, been proceeding with alternative plans to complete a lesser capacity, 230kV transmission system of its own, designed to transfer power from Utah to numerous ::ODMA\PCDOCS\HLRNODOCS\566656\1 Page 3 1 2 3 4 5 6 7 8 9 Q. 10 i 1 12 A. 13 14 15 16 17 18 19 20 21 22 23 Q. 24 25 26 27 28 SNWA receipt points. The SNWA has a 100MW ownership interest in the Intermountain Power Project's new coal facilties ("IPP3"). This independent course by the SNWA is necessary to assure its ability to complete in a timely fashion the water delivery system required by southern Nevada. And, while I have not been heavily involved in the ongoing coordination efforts, I have been assured that the SNWA intends to continue coordinating with Nevada Power in recognition of the needs of both parties. HAS THE SNWA CONSIDERED TAKING TSA SERVICE OFF OF THE NEVADA POWER PROPOSED 500KV LINES RATHER THAN CONSTRUCTING ITS OWN LINES? Yes. This is not at all an option satisfactory to the SNWA because of the inabilty to use its low cost capital to construct the lines, the inabilty to require all critical deadlines for construction to be met, and the need for lower voltage service. TSA service and its expected higher transmission rates is not considered to be a feasible option to the SNWA. Additionally, SNWA has other public partners with additional ownership interests in IPP3 with which it is now coordinating. J provide this background to inform the Commission that Nevada Power and SNWA are in continual dialogue regarding the coordination and cooperation of both parties' proposed transmission facilties. At this time SNWA's direct involvement in Nevada Power's Intertie does not appear likely. IS SNWA REQUESTING THE COMMISSION TO ORDER NEVADA POWER TO DO ANYTHING SPECIFIC IN THIS DOCKET TO ACCOMMODATE SNWA'$ TRANSMISSION NEEDS ASSOCIATED WITH THE SNWA WATER IMPORTATION PROJECT? ::ODMA\PCOOCS\HLRNOOOCS\56656\1 Page 4 1 A. 2 3 4 5 Q. 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 No. SNWA wil continue to discuss possible involvement in the Intertie with Nevada Power and commits to also discussing right-of-way and EIS issues with Nevada Power as those issues arise. WHAT SPECIFIC CONCLUSIONS HAVE YOU REACHED IN REGARD TO THE IRP, ENERGY SUPPLY PLAN ("ESP") AND ACTION PLAN FILED BY NEVADA POWER? A. I conclude that: Plan Endorsement 1. Although the preferred plan is not at all the least costly of the plans reviewed, it provides generation capacity which is eventually needed in the Nevada Power system and should generally be supported by this Commission. ESP, Action Plan Application, pp. 35.37. Critical Facilty Designation 2. Any designation of the EEC and Intertie as Critical Facilities or a denial of this designation is premature at this time and should await more maturity in development of the plan. A final ruling on this matter should be deferred until at least sometime in 2008. 3. The Commission should approve the plan as modified in its discretion, but allow AFUDC on construction work in progress (CWIP), not CWIP in rate base, until such time as it makes a final determination on Critical Facilties. 4. Nevada Power should be required to clarify its request for an incentive return" . . . calculated at 2% above Sierra's authorized weighted return on equity. . ." (Application, p. 14 of 16, i. 4-5, and elsewhere). Specifically, a 2% weighted return on equity, calculated at a 40% equity ratio, translates to a requested incentive ROE adder of 5% to the presently allowed equity return. Even a" 2% ROE adder to an unweighted ROE amounts to a $935 millon excess pretax bonus to shareholders over and above its fair rate of return and should be rejected. 5. The Commission, in following the recommendation to defer final determination of whether the EEC and the Intertie are Critical Facilties, or not, should require certain milestones to have been reached, including, but not limited to, the granting of a final air permit from the Nevada Departent of EnvironmentalProtection, scheduled for January 2008. ' fill ~I1 ::ODMA\PCOOCS'HLRNODOCS\566656\1 Page 5 1 Plan Endorsement WHAT IS SNWA'S POSITION WITH RESPECT TO NEVADA POWER'S PROPOSED IRP, ENERGY SUPPLY, AND ACTION PLAN? The SNWA generally endorses moving forwrd with the planning and permitting of the Ely Energy Center. related transmission facilities, including the I nterte , other transmission facilities in Clark County, and the approximate 600 MWs of quick start combustion turbines at Clark Station. (Application, Items 5,6, 7, 8.) The SNWA did not review in detail, and therefore remains silent on, the proposed load and sales forecast and the fuel and energy market forecasts. (Application, Items 3 and 4.) The SNWA opposes at this time the Company's request to have the Commission designate Phase One of the EEC and Intertie as Critical Facilties. (Application, Item 9.) 2 Q. 3 4 A. 5 6 7 8 9 10 ii 12 13 14 15 Q. 16 17 A. 18 19 20 21 22 23 24 25 26 27 Q. 28 WITH RESPECT TO THE EEC, THE INTERTIE, AND THE CLARK STATION ADDITIONS, WHY IS YOUR ENDORSEMENT ONLY "GENERAL"? Nevada Power should be encouraged to proceed with its extremely ambitious plans with respect to these facilties. For decades now, the Company has been deficient in own-generation facilities. The recent additions of the Silverhawk and Lenzie generating plants. together with the 2,100 MW of requested coal and CT plants, could shield Nevada Power and its customers from the risk of capacity cost swings possible from any potentia' future resource shortges. The reason that the SNWA endorsement is cautious is due to the extreme uncertinty with respect to any actual building of Phase One of EEC, and the interdependence of the associated transmission, the Intertie and even the Clark ÇTs. PLEASE EXPLAIN. ::ODMA\PCDOCS\HLRNODOCS\566656\1 Page 6 1 A. 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Q. 19 20 A. 21 22 23 24 25 26 27 28 Quite some time has elapsed since the completion of major coal facilties in the western U.S. and, according to the testimony of Nevada Power, the Company is stil assessing the viabilty of various supercritical boiler and emissions control technologies (Sims, p. 9, i. 15-18). i am aware of no U.S. projects identical to the Company proposal that have been completed on a commercial basis in recent years. i understand that certin types of supercritical facilties have been built in Asia. And, while the relatively stable nature of the price of coal makes new coal facilities attractive, we are all aware of the potential siting, environmental, and transmission diffculties associated with large planned coal plants. Today, there exist both strong proponents and opponents of major new coal generating facilities. And, while EEC is represented to include ". . . the latest clean-eoal technologies. . ." (June 30, 2006, NPC press release), the siting, water, transmission construction, permitting, and public endorsement of the facilty wil certainly pose a significant challenge. For these reasons, the SNWA urges the Commission to grant only preliminary approval, but require extraordinary updating and progress reports with appropriate off ramps should the project become mired in diffculties. WHY DO YOU CHARACTERIZE PHASE ONE OF EEC, RELATED TRANSMISSION, THE INTERTIE, AND THE CLARK CTS AS INTERDEPENDENT? The IRP planning process evaluates the totality of the existing electric system, together with all of the proposed preferred and alternative plan additions. The need for and optimality of each component is crucially dependent on the succssful completion of each and all other proposed facilities. Withou knowledge of the completion of, say, the preferred plan as proposed, there is no expectation that the project is economic (has lowest present worth of revenue requirements, PWRR). For example, the demise of either the ECC or the Intertie individually would require complete rethinking of the remaining project. And, due to the need to economically fil Nevada Power's load duration curves, loss of either the EEC or the Intertie would call ::ODMA\PCDOCSIHLRNOOOCS\566656\1 Page? i 2 3 4 5 Q. 6 7 8 A. . 9 10 11 into question the feasibilty of the Clark Station CTs, versus perhaps the more effcient technology of combined cycle CTs. These considerations underscore the need for timely updates, status reports, and possible alterations of the preferred plan. DO THE UNCERTAINTIES YOU HAVE REFERENCED REQUIRE CHANGES TO THE GENERATION ADDITIONS SECTION (VOL. 1, PAGE 35) OF THE RESOURCE PLAN? No. With the exception of the request for Critical Facilties designation, i don't believe that the requested ESP and Action Plan require changes for my proposal to require frequent status updates. Nevada Power's request for approval for up to $300 milion through 2008, qualified by its successful receipt of its air permit should allow Nevada 12 Power to move forward unless and until any subsequent plan obstacles are 13 encountered. 14 i 5 Critical Facilties Designation 16 Q. 17 18 19 A. 20 21 22 23 24 25 26 27 28 WHAT ISSUES DO YOU HAVE WITH RESPECT TO NEVADA POWER'S REQUEST TO HAVE THE COMMISSION DESIGNATE PHASE ONE OF THE EEC AND THE INTERTIE AS CRITICAL FACILITIES? Under NAC 704.9484, I understand that Nevada Power may request that a facility of the utility be designated as a Critìcal Facility. I also understand that the Commission. upon such a request, may determine whether to designate such a facility as criticaL. In its order in Docket 04-6030, the Commission approved a.similar request by Nevada Power to designate the (now-named) Lenzie Energy Facility as a Critical Facilit. The issue I raise in regard to the Company's request for Critical Facility designation for the EEC and Intertie facilties is that at the present time it is simply not possible to conclude that these proposed facilities may meet any of the purposes listed in paragraphs (a) to (e) of the code. The facilities should not, therefore, be designated as Critical at this point. Such a finding would be premature at best. ::ODM\PCDOS\HLRNODOCS\56656\1 Page 8 1 Q. 2 3 A 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Q. 19 A. 20 21 22 23 24 2S Q. 26 27 A. 28 WHY DO YOU CONCLUDE THAT THE EEC AND INTERTIE FACILITIES CANNOT NOW BE FOUND TO COMPLY WITH PARAGRAPHS (A)-(E) OF NAC 704.9484? These paragraphs set the standards of: (a) Protecting reliabilty; (b) Promoting diversity of supply and demand side sources; (c) Developing renewable energy resources; (d) Fulfillng specific statutory mandates; (e) Promoting retail price stabilty; (f) Any combination of paragraphs (a) to (e), inclusive. Given the greenfield nature of these proposed facilities, the lack of a definitive location to site the EEC, an undetermined and unproven new emissions control technology, uncertain water supply , permitting activities stil in process, and considerable lead times necessary to bring such coal facilities into commercial operation, no meaningful conclusions can be reached at this time with regard to the degree, if any, to which the EEC and 'ntertie may eventually enhance system reliability, diversity of resources or price stability to the Nevada Power system. ARE YOU INDICATING THAT THE EEC AND INTERTIEWILL NOT BE BUILT? No. As I have stated, the SNWA supports the continued study and potential development of these facilties. But, in stark contrast to the Lenzie facilty that was well underway and partially constructed and purchased at a large discount to market prices for new construction, the EEC and Intertie are stil in the very early, or "greenfield" stage of development. WHY DO YOU CHARACTERIZE THE EEC AND INTERTIE AS BEING IN A VERY EARLY OR "GREENFIELD" STAGE OF DEVELOPMENT? This is the same characterization used by Nevada Power (Sims, p. 3, i. 16-19). Also, according to Nevada Power witness David Sims, Nevada Power and Sierra Pacifc ::ODMA\PCDOCS\HLRNODOCS\566656\1 Page 9 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 J 8 19 20 Q. 21 A. 22 23 24 25 26 27 28 have together expended only $1 millon in .. . . . preliminary development costs and studies on the project. . ." (Sims, p. 10, i. 19-20.) Thus, to date, only .027% of the expected project costs have been expended, and this on preliminary development. According to Mr. Sims, some of the preliminary work includes: -Identifcation of two potential sites (p. 3, i. 7) -Review for "greenfield" development of coal generation (p. 3, i. 19) -Participating in two studies to assess the viability of new emissions control technologies (p. 7, i. 17-18) -Overcoming the fact that the "only proven process" for reducing C02 emissions would consume roughly one-third of a plant's power output and increase the cost of its electricity by 60-80%. (Cite) Nevada Power; to its credit, candidly admits to the infancy of the study and development of the EEC facilty. At present, there are no site, air permits, water, proven technologies, emissions plan, fuel supplies, and transporttion or definitive approvals for the EEC. In my opinion, there is no basis for concluding at this time that the EEC and Intertie are in any way critical among the numerous supply plans reviewed and analyzed. The Commission should postpone its determination of cnticality and await the attainment of milestones prior to making this decision. WHAT TYPE OF MilESTONES MIGHT THE COMMISSION REQUIRE? In addition to awaiting the engineering and design to take shape, the awarding of a final air permit by the Nevada Department of Environmental Protection (estimated January 2008), the final EIS (estimated May 2008), and the BlM Record of Decision (estimated July 2008) would be good indicators of whether the actual project is progressing. Also, a report from Bums & McDonnell indicating whether it has or has not been able to determine from its study whether the various supercritical boiler and emissions technologies, and site construetabiJty are viable would be very useful (Sims, p. 9, i. ::ODMA\PCDOCS\HLRNODOCS\566656\1 Page 10 2 3 4 5 Q. 6 7 8 9 A. 10 11 12 13 14 is 16 Q. 17 A. 18 19 20 21 Q. 22 A. 23 24 25 26 27 28 15-29). After this it may be possible, with at least some degree of confidence, to begin to predict whether and when these facilities are likely to add reliability, diversity and price stabilit to the Nevada Power system and its customers. IF THE COMMISSION CHOOSES TO DEFER ITS DETERMINATION REGARDING THE REQUEST FOR CRITICAL FACILITY DESIGNATION, HOW DO YOU RECOMMEND THAT EXPENDITURES ON THESE FACILITIES BE ACCOUNTED FOR? I recommend that, prior to final Critical Facilities designation, all such expenditures be treated for accounting purposes consistent with current accounting methods. The expenditures would earn AFUDC, but not CWIP in rate base at this time. Thus, upon any eventual future designation as Critical Facilties, only expenditures subsequent to the determination would be eligible for favorable treatment and then only if granted at that time by the Commission. ARE YOU GENERALLY IN FAVOR OF ALLOWING CWIP IN RATE BASE? No, not generally. In my opinion, awaiting a final determination of rate base treatment until facilities are clearly "used and useful" has been a superior form of regulatory treatment for new construction. PLEASE EXPLAIN. The arguments against a regulatory convention granting CWIP in rate base are not new to Nevada. In the instant proceedings, however, the uncertainty, magnitude and preliminary nature of the proposed plan argue further for not allowing CWIP in rate base at this time. The primary shortcomings of Nevada Power's request for CWIP in rate base at this time are twofold. One, the long lead time, coupled with the preliminary status and accompanying completion risk of the project at this time, would ::ODMIPCDOCS'lLRNODOCS\56656\1 Page 11 1 significantly raise present customers' rates far in advance of any genuine expectation 2 of the "used and usefulness" of the preferred plan. 3 Secondly, the Commission should always attempt to align, to the extent 4 possible, the benefits of resource additions with the customers receiving such benefits. 5 Under the Company's preferred plan l the long and probable lengthening of the 6 suggested lead times to reach commercial operation of Phase One of the EEC and 7 Interti$, would necessitate significantly higher rates in the next several years to be 8 borne by customers prior to commercialization. Correspondingly, the rates to 9 custoniers consuming energy from the date of commercialization and extending over lO the life of the EEC and 'ntertie projects would be lower. The accounting convention of 11 AFUDC better aligns project costs with customers enjoying the benefits of the projects. 12 The arguments i have just cited are not meant to argue absolutely against the granting 13 of CWIP in rate base, as NAC 704.9484 clearly allows this consideration, but instead 14 to point out the serious objections of granting the request so far in advance of the 15 reasonable knowledge of the success of the proposed projects. 16 18 Q. 17 ROE Incentive Return 19 20 A. 21 22 23 24 25 26 27 ,Q, 28 WHAT ARE YOUR ISSUES WITH RESPECT TO NEVADA POWER'S REQUEST FOR AN INCENTIVE RETURN ON EQUITY FOR THE EEC AND THE INTERTIE? The primary issue i raise with respect to the Company's requested 2% ROE adder is the excessive burden it pl~ces on ratepayers, especially in light of the fact that the preferred plan with EEe and the Intertie is not the least cost of plans analyzed by \ Nevada Power. First, however, there is a need for clarification with respect to the Company's 2% ROE adder request. WHAT CLARIFICATION DO YOU SEEK WITH RESPECT TO THE COMPANY'S REQUEST FOR A 2% ROE ADDER? ::ODMA\PCDOCS\lLRNODOCS\56656\1 Page 12 1 A. 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Q. 16 A. 17 18 19 20 21 22 23 24 Q. 25 A. 26 27 28 In at least three places in its filing, Nevada Power requests an ROE incentive return ". . . calculated at 2% above Nevada Power's authorized weighted return on equity "(Application, p. 14, i. 5-6; Yackira direct, p. 14, i. 15-16; Vol. 1 ESP, p. 36,11 4) (emphasis added). The term "weighted return on equity" in cost of capital parlance indicates that the Company is requesting far more than a simple addition of 2% to its authorized equity return of 10.25%. The authorized 10.25% equity return is an unweighted equity return. To reach an overall allowed rate of return on capital, the unweighted equity return is multiplied by the equity ratio and added to the unweighted debt cost multiplied by the debt ratio. The reason that the issue of whether the Company really is requesting a 2% adder to the weighted equity return is so important is because a 2% equity return added to the authorized weighted equity return actually grants the Company the equivalent of a 5-6% ROE adder. PLEASE EXPLAIN. My Exhibit 1 (DEP-1) demonstrates the significant difference between adding a 2% ROE adder to the authorized unweighted return and adding a 2% ROE adder to the authorized weighted equity return. For clarity of example, the comparison is made assuming a 10.25% authorized equity return, 7% debt costs, and a 57/43% debt- equity to capital ratio. As shown in the exhibit, if the requested 2% ROE incentive is added to the weighted return (the 4.41 %) As literally requested by Nevada Power. the result is to actually grant shareholders a 14.9% overall equity return. DID YOU ATTEMPT TO CLARIFY THIS ISSUE WITH NEVADA POWER? Yes. In response to SNWA-1, the Company indicated that it would apply the 2% ROE adder to the unweighted return on equity. . I attach a copy of this response as Exhibit 2 (DEP-2). Since the Company filing stil indicates that the 2% ROE adder is to be ::ODMA\PCDOCSIHLRNOOOCS\S666561 Page 13 2 3 4 Q. 5 6 A. 7 8 Q. 9 10 11 12 A. 13 14 15 16 17 18 19 20 21 Q. 22 23 A. 24 25 26 27 28 added to the weighted return on equity, my testimony above is intended to note this inconsistency and clarify the intent and extent of the ROE incentive adder. HOW WAS THE 2% ROE ADDER TREATED WITH RESPECT TO THE INCENTIVE RETURN ON THE LENZIE ENERGY FACILITY IN DOCKET 04-60301 The 2% ROE adder was added to the unweighted equity return (Order, Page 23). ASSUMING THAT NEVADA POWER'S REQUESTED 2% EQUITY RETURN INCENTIVE IS MEANT TO BE ADDED TO THE AUTHORIZED UNWEIGHTED EQUITY RETURN OF 10.25%, WHY DO YOU CHARACTERIZE THE 2% AS EXCESSIVE? If allowed, the requested 2% incentive adder on the unweighted equity return wil provide investors with a $935 milion bonus in nominal dollars over the life of the projectl If the Company's request is for the adder to be on the weighted equity return, that bonus is increased to approximately $2.1 billon. And, at the same time, the additions of the Lenzie and Silverhawk plants, together with the completion of more than $4 billon in new generation, transmission, and DSM facilties (Vol. II, Action Plan, Table AP-1) wil greatly increase the present level of rate base of Nevada Power and provide investors with growing returns. WHY DO YOU SAY THAT NEVADA POWER'S REQUESTED 2% ROE BONUS WILL 'PROVlpE INVESTORS WITH $935 MILLION IN ADDITIONAL PROFITS? The essentials of this calculation are shown in Exhibit 3 (DEP-3). The budgeted expenditures for the EEC and Intertia investment are capitalized and given the additional 2% ROE adder over the life of the assets. Exhibit 3 (DEP-3) calculates a total incentive-related revenue requirement over the lives of the assets of $935.024,000 (for 100%). 80% of which is proposed to be charged to Nevada Power customers. ;:ODMA\POOCS\HLRNODOCS\5666561 Page 14 1 Q. 2 3 A. 4 5 6 7 Q. 8 A. 9 io 11 12 13 14 15 16 17 18 Q. 19 A. 20 21 22 23 24 25 26 27 28 WHY DO YOU CHARACTERIZE THE $935 MILLION INCENTIVE BONUS TO INVESTORS AS EXCESSIVE? First, and perhaps foremost, the propose new EEC and Intertie facilities, while a welcome change from exposure to market power, will already be a boon to investors without a $935 millon bonus. PLEASE EXPLAIN. In recent years, Nevada Power investors have been disadvantaged by the Company's lack of generation resource additions dating back to the early 1990s. I realize that Nevada. like a number of other states, had an interlude where the advent of market competition required a pause in utilty generation additions. As a result, the bulk of the Company's revenue requirement in the last decade and a half has been comprised of significant expenses upon which investors earn no money. Relative to many other electric utilties, Nevada Power's preference for market purchases, combined with significantly depreciated existing generation facilties, has made the Company less attractive in terms of investors' earnings base. 15 THE LACK OF CAPITAL INTENSIVENESS CHANGING FOR NEVADA POWER? Yes, very much so. And again, this is a good thing, for the. most part, for both the Company's shareholders and its customers, if rates can be kept from increasing unnecessarily. The requested 2% ROE incentive adder is entirely unnecessary. Nevada Power's rate -base in 2005, according to the filing in Docket No. 06- 01016, was $2.3 bilion. Upon completion of the proposed EEC, the Intertia, and other transmission facilties, the Company's rate base could easily be $6 or 7 billon, or 3 times the 2005 leveL. In my opinion, the recent positive financial strides experienced by Nevada Power and the favorable increases in earnings assets just noted wil allow the Company to reach investment grade status very soon and does not require the additional $935 milion incentive. ::ODMA\PCDOCS\HLRNODOCS\566656\1 Page 15 1 Q. 2 3 A. 4 5 6 1 8 Q. 9 10 A. II 12 13 14 15 16 17 18 19 20 21 Q. 22 23 A. 24 25 26 21 28 HAVE INVESTOR INSTITUTIONS RECOGNIZED THE POSITIVE INVESTMENT AND GROWING ASSET OUTLOOK FOR NEVADA POWER? Yes. For example, on September 11, 2006, Deutsche Bank upgraded SPR from a hold to a buy recommendation, increasing its stock pnce target from $14.50 to $16.50 as a result of infrastructure growth. My Exhibit 4 (DEP-4) contains excerpts from press releases on this topic. ARE THERE OTHER REASONS WHY YOU CONSIDER THE COMPANY'S REQUESTED 2% ROE ADDER EXCESSIVE? Yes. No one should forget that the last few years have arguably been as diffcult for Nevada Powets customers as it has been for its shareholders. In 1999, for example, Nevada Power retail rates were relatively low compared with other western electrics. Today, Nevada Powets rates rank among the highest in the West, exceeded only by the most expensive California electrics, as clearly illustrated in the Supplemental Testimony of Company witness Anthony J. Karr. Given this, the rapidly increasing earnings base being experienced by the Company, and the fact that management is just doing its job in building adequate resources to serve its load, customers ought not be burdened with also paying greater profits to shareholders. IS NEVADA POWER'S REQUESTED PREFERRED PLAN THE LEAST COST AMONG THE NUMEROUS PLANS IT ANALYZED? No, a number of the plans analyzed by the Company have lower lifetime costs. As summarized in Technical Appendix II, Supply Side Book at least four of the alternative plans analyzed by Nevada Power have lower costs than the preferred plan. These are Case Nos. 13, 15,4 and 12. ::ODMA\PCDOCS\HLRNOOOCS\566656\1 Page 16 r i Q. 2 3 A. 4 5 6 7 8 9 10 ii 12 Q. 13 A. 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 DO THE FOREGOING FACTS REGARDING THE MORE EXPENSIVE REQUESTED PREFERRED PLAN ARGUE FOR REJECTION OF NEVADA POWER'S REQUEST? No, as I have stated, despite the fact that the preferred plan is more costly than others, the SNWA supports at least the initial pursuit of the plan. My criticism in this regard is that Nevada Power's requested $935 millon excess burden on this plan is on top of an analysis that even absent this bonus, the preferred plan is considerably more expensive than several alternatives. This, and consideration of the preferred pIan's clear benefits for shareholders. lead me to conclude that in fairness to customers, at no penalty to shareholders, the Nevada Power request for the 2% ROE adder be denied at this time. PLEASE SUMMARIZE YOUR CONCLUSIONS The SNWA generally endorses the proposed IRP. At this stage. however, there clearly exist numerous elements to be studied and analyzed before full approval should be granted by th'e Commission. Specific and frequent. updates and progress reports $hould be required to be provided by the Company as a means of confirming the viabilty and feasibilty of the proposed resource plan, Energy Supply Plan, and associated Action Plan. The Commission, in my opinion, lacks any signifcant information at this time regarding how useful and "critical" the proposed plan wil eventually be. As a result, a judicious step would be to postpone and defer any requested ruling on Critical Facilties status until at least sometime in 2008. Any conclusions on the approval of, or extent of any favorable accounting and equjty return incentives, should also be postponed and evaluated again later in light of the balance between customer and shareholder interests. .. ::ODMA\PCDOCS\HLRNODOCS\566561 Page 17 AFIRTION I, Denns E. Peseau, puruant to NAC 703.710 hereby af that the foregoíng prepared testimony was prepared by me or under my direction and is correct to the best of my knowledge. dJ'dRdDen ¥Peseau Dated: 1-13 - Ð (0 Page 18 Atthment 1 Dkt 06-08051 Witnes: D,E. Peseau Page 1 of3 STATEMENT OF OCCUPATIONAL AND EDUCATIONAL HISTORY AND QUALIFICATIONS DENNIS E. PESEAU Dr. PeseaU has conducted economic and financial studies for regulated industries for the past twenty-eight years. In 1972, he was employed by Southern California Edison Company as Associate Economic Analyst, and later as Economic Analyst. His responsibilities included review of financial testimony, incremental cost studies, rate design, econometric estimation of demand elasticities and various areas in the field of energy and economic growth. Also, he was asked by Edison Electrical I nstitute to study and evaluate several prominent energy models as part of the Ad Hoc Committee on Economic Growth and Energy Pricing. From 1974 to 1978, Dr. Peseau was employed by the Public Utilty Commissioner of Oregon as Senior Economist. There he conducted a number of economic and financial studies and prepared testimony pertaining to public utilties. In 1978 Dr. Peseau established the Northwest offce of Zinder Companies, Inc. He has since submitted testimony on economic and financial matters before state regulatory commissions in Alaska, California, Idaho, Maryland, Minnesota, Montana, Nevada, Washington, Wyoming, the District of Columbia, the Bonnevile Power Administration and the Public Utilties Board of Alberta on over one hundred occasions. He has conducted marginal cost and rate design studies and Attachment 1 Dkt. 06-06051 Witness: D.E. Peseau Page 2 of 3 prepared testimony on these matters in Alaska, California, Idaho, Maryand, Minnesota, Nevada, Oregon, Washington and in the District of Columbia. He has also conducted cost and rate studies regarding PURPA issues in the states of Alaska, California, Idaho, Montana, Nevada, New York, Washington, and Washington, D.C. Dr. Peseau holds B.A., M.A. and Ph.D. degrees in economics. He has co-authored a book in the field of industrial organization entitled, Size, Profits and Executive Compensation in the Large Corporation, which devotes a chapter to regulated industries. Dr. Peseau has published articles in the following professional journals: Review of Economics and Statistics, Atlantic Economic Journal, Journal of Financial Management, and Journal of Regional Science. His articles have been read before the Econometric Society, the Western Economic Association, the Financial Management Association, the Regional Science Association and universities in the United Kingdom as well as in the United States. He has guest lectured on marginal costing methods in seminars in New Jersey and California for the Center of Professional Advancement. He has also guest lectured on cost of capital for the public utility industry before the Pacific Coast Gas and Electric Association, and for the Executive Seminar at the Colgate Darden Graduate School of Business, University of Virginia. Attachment 1 Dkt. 06-06051 Witness: D,E. Peseau Page 3 of3 Dr. Peseau and his firm have participated with and been members ofthe American Economic Association, the American Financial Association, the Western Economic Association, the Atlantic Economic Association and the Financial Management Association. He was formerly a member of the Staff Subcommittee on Economics of the National Association of Regulatory Utilty Commissioners. Dr. Peseau has been President of Utilty Resources, fnc. since 1985. Old. 0606051 Peseau Direct Testimony Exhibit DEp.1 Page 1 of 1 Nevada Power Company Effec Of 2% ROE Il1centlv on Weighted and Unwejghted EqUity Return Sourc Debt Preferred Equity COmmon Equity Marginal Cost of Ca~tal . Base Unwelghted Cost 7.00% 0.00% 10.60%1 Weight 57.00% 0.00% 43.00%J Welghtèd Cost 3.99% 0.00% 4.56%1 Tota 8.55% Marinal Cost of caitl. 2% ROE Incenti Added to Weighted Equlty Cost Unweiht WeighledCost Weight Cost' 7.00% 57.00% 3.99% 0.00% 0.00% 0.00% 15.25% 43.00%1 6.5:%1 Source Oébt Prefe Equft COmmo Equit Tota 10.55% Margnal Cos of Cspil-2% ROE InC$ti added to Unweihtd EQuJ Cot Unweghted WeighteCo Wetaht Cost 7.00% 57.ooDIo 3.99% 0.00% 0.00% 0.00% 12,60%1 43.00% 5.42% 800rc Deb Prefed EquIty Comon Equity Tota 9-41% Dkt. 06-0051 Peseau Testimony Exhibit DEP-2 Nevada Power Company RESPONSE TO INFORMATION REQUEST DOCKET NO.: REQUEST NO.: REQUESTER: 06-06051 REQUEST DATE:8/23/2006 SNWA1 RESPONDER:Karr, Tony REQUEST: Please confimi tht Nevada Power Company ("NPC") intends, as Îs stated in Yackira Direct, p. 14, i. 15-16 and p. 36, ESP, Vol. I, to request an incentive return ti. , . caJcuJated at 2% above Nevada Power's authorized weighted return on equity. . . ." or is the request for 2% above its unweighted return on equity? Please provide a detailed example of the calculation of the incentive return as requested by Nevada Power for eventual cost recovery. CONFIDENTIAL (yes or no): No. RESPONSE: Nevada Power Company would apply the requested incentive ROE of 2.00% to the unweighted return on equity. Assuming the authorized ROE is equal to the cost of capital of 10.60% (used in this filing), the unweighted equity component wil equal 12.60%. The marginal weighted cost of capital with the ROE incentive would total 9.41 %. This is an increase of 86 basis points from the total weighted cost of capital of 8.55% used in the filing. Marginal Weighte cost ot Capn.i i.sc Welgnt Weigted Cost Debt 7,00%57.00%3.99% Prferred Eauity 0.00%0.00%0,00% I,ommon Equit 1Z.6oYo 4::.00%5.42% Total 9.41% Nt V i P o w e r C o m p a n y ~~ ~ , , l . m v ~ I : ¡ ¡ . 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I . u s e 2 , 1 It . 1 5 i , a f l A 0 ' . T $ 1O 7 s ; r t t f t , 3 1 . 1 4 .. . , I , l U 8 1 1 , 3 1, 4 , 1 1 4 , 2 ' , 1 1 1 1 1, 1 4 . 8 1 0 1 3 , 1 7 0 1 1 5 4 '# 1 o U 1 2 , 1 1 1 l O a 1' . I A 3 , i U S l m t 1, 4 3 , . . 7 b I 6 I uo 3 , 1 2 1 1 , 2 . . s. 1 7 2 , 7 1 r . 7 , 7 3 : i 4" ' . 2 , 5 G 1 i : i 3. 7 4 0 2 . ' - 5 . 7 P 2 3 3. 0 ' 1 1 , ' " " , 7 - t 1 7 1 1, 0 7 3 1 0 1 i , S J 1, 4 1 1 l 0 U N n 5! _ W 2 : ~: i m T 4 1 2 Ø 04 0 8 Ø I 1 2 1 . æi 1 1 0 5 1 3 1 2 zl l 1 - 4 _ . ~8 $ , C C 2 8 . II I 8 0 1 1 1 : I 17 4 1 U . % 5 : I I 0 5 : I B 0 o 0 0 0 D 0 0 0 .7 , 7 6 5 :i . z 9S J l 27 2 . 1 8 3 CI I i * r l J 5 ~ol .: l 1 5 5U 4 7 n, O O lØ 3 0 2 12 4 , 5 9 14 3 . 4 1 1 10 0 . 2 0 17 4 0 9 5 18 7 " l _, 3 7 20 . " ' 21 8 , 2 22 . m =u ' W 23 2 2 24 , 4 2i 7 . i - 21 1 , , 2$ S 2 25 7 , 3 3 2Ø . " ;Z 1 , G ? 8 :i Q . 4 2 7 2l . l M ' . 2 l , 2 e 2l . ; 2I , 3 i i i _, 1 2 8 2& , 8 5 nu n 2l l . N 7 71 1 , 1 $ 21 1 , 6 1 7 27 1 . 7 $ 1 :r . m 27 0 1 1 Z7 O t , m, 1 1 7 27 2 . 3 1 Z1 . 1 5 2 Z7 2 1 6 l %7 1 7 2 %7 l 1 ' 8 m, 1 e l 27 2 1 1 21 ' " 21 2 . 1 & ) 21 f l 3 Z7 I U 27 ' 8 3 "l (J io ma ' o "l š - S l ¡ : II 6 ' - i (Q _ , ( J 2 (I - U l ' t ' o i = 0 ~m 3 0 ) sa 1 ' 2 g -a t t ~ ~ Dkt. 0606051 Peseau Testimony Exhibit DEP-4. 1 of 2 frWBûšìèš · Markets . Analyst News · Technoiogy News . Press Releases · By Industry · My Portfolio News Sierra Pacific Resources upped at Deutsche Bank 6:11:10 AM ET 9/11/2006 LONDON (MarketWatch) -- Deutshe Bank upgraded electric utilty Sierra Pacific Resources (SRP) to buy from hold and raised its price target to $16.50 from $14.50, citing required infrastructure growth in its Las Vegas and Surrounding Nevada service territories. .. = -_.. ~--~ ==''==..~i;__a.._~..''~~ ie:'l~-:;'''-i~..=~~~~~~..:: i:wmi. =: -= 2 .- C:jl$Si+ ==i'ë..~~ .c:r ..m== Market1latch r--'''.''--'- ....-. I' û' "1 . ".- ,r;.:~'~ ~' i...);" lI ".. ._ ,i. .' ! i .~;~~..:. . . ! t:..~:l\.:r:":.-. ffo I'-.r~~i:~ l .; "--~..!"....,,, I Okt. 06-06051 Peseau Direc Testimony------~,------.-__Exhibit.OEP.,_4,_ Page 2 of2 Subject: Reuters.com - UPDATE 1-RESEARCH ALERT-Deutsche Bank upgrades Sierra Pacific - Man Sep 11,2006 11:46AM ET REUTERS :;D UPDATE 1.RESEARCH ALERT-Deutsche Bank upgrades Sierra Pacific Man Sep 11, 200611:46 AM ET (Changes sourc, adds details) Sept 11 (Reuters) - Deutsche Bank on Monday raised its rating on Siena Pacifc Resources .cSRP.N~ to "buy from -hold" and incresed its 12-month price taret by $2 to $16.50. In a research note, the brokerage said the upgrade was based on its updated work on the utUit ownets require infrastructure growth in its Las Vegas and surrounding Nevada servce territories. The "preferred" Ely Energy Centr pulvrized col integrated resource plan is the lower cost and most atractive generaion development proram for ratepayers over the long term, compared to higher cot and volatile natural gas fired generation, the broerage said. This, along with the potential for critical facilty status, has the added benefit of additional gain and value creation for shareholders, it added. Shares of the company rose over 2 percent to $14.70 in morning trade on the New York Stock Exchange. (Reporting by Sweta Singh and John TUak in BangaJore) ......... ._.. .... ......----.. _......__.... .. .... .....__.........___...__.__.. ..._.. ...... ___".__M_ .._. __.._. ,_..___.._. _ _.'_.'___ ......._ .. ___..~_ .. ....__ . This service is not intended to encourage spam. The details provided by your coDeague haiie been used for the sale purpose Of faciJtattng this email communication and have not ben reained by Reuters. Your persal details have not been added to any database or mailng list. If you would like to reeive news articles delivere to your email addrs, please subscribe at WW.reuters.co .. _.._._-....._-..__._-- -_._--_...__._- .. ......-------..._.._--..--_.._...-....-- ._- .._._.--.._-...._. .~_.._-- - --_....-_._-..._.-- ._-- .. _...- .__.. .. .. ~ Copyright Reuters 2006AII rights reserved. Users may download and print extracts of content from this webite for their own personal and non-commercial use only. Republication or reistrilution of Reuters content, including by fraing or similar means, is expressly prohibited without the prior written consent of Reuters. Reuters and the Reuters sphere log are registere traelfarks or trademarks of the Reuters group of companies around the world. Quotes all other data are provided for your personal information only, and are not intended for trading purposes. Reuter, the members of its Group and its data providers shall not be liable for any errrs or delays in the quotes or other data, or for any actions taken in reliance theren. (! Reuter 2006. All rights reserved. Republication or redistribution of Reuters content. including by caching, framing or similar means, is expressly prohibited without the prior writen consent of Reuters. Reuters and the Reuters sphere logo are register traemarks and trademarks of the Reuters group of copanies around the world. 9112/2006 2 3 4 5 6 7 8 9 "Ø 10"0;0 o C' ..11:r 80... .."Ø :: 0\12 ã 00 00~ ~g ti ~13.~ ~ )-i: fI ~C Z 14 . ö.~i 15.l.....4) =u4) ~ i: i:.. 0 164) l/ ~ iä r3 17i- l" U 4) i-~ l"18:i 19 20 2) 22 23 24 25 26 27 28 PROOF OF SERVICE I hereby certify that I served the foregoing Direct Testimony of Dennis E. Pescau on behalf of SNWA in Docket 06-0605) by sending via electronic mail to the following addresses and by delivering to the U.S. Post Offce copies thereof, properly addressed for mailng and postage pre-paid to the following persons: Douglas Brooks, Esq. Sierr Pacific Power Company P.O. Box 98910 6226 West Sahar Avenue Las Vegas, Nevada 89 i 51 dbrooksCWneyp.com Staff Counel Public Utilties Commission of Nevada i 150 E. Wiliam Street Carson City, NY 89701-3109 uttingerl§puc.state.nv. us Elizabeth Ellot, Esq. Sierra Pacific Power Company 6100 Neil Road Reno, NY 895 I 1 bellott!sppc.com Alaina Burtenshaw Public Utilties Commission 101 Convention Center Drive, Suite 250 Las Vegas, NV 89109 aburtens~puc.state.nv. us Paul Stuhff Burau of Consuer Protection 555 E. Washington Street, Ste. 3900 Las Vegas, NV 89101 pestuhffi§ag.state.nv.us Nancy Barker Nevada Power Company 6226 W. Sahar Ave.. MS3A Las Vegas, NY 89146 nharker(ßnevp.com Dale Stransky, Senior Engineer Bureau of Consumer Protection lOON. Caron Street Carson City, NV 89701 dastrans(gag.state.nv. us Kathleen M. Drakulich, Esq. Kummer Kaernpfer Bonner. et aI. 3800 Howard Hughes Parkway, 7th Floor Las Vegas, NV 89109.0907 kdrakulichWdbr.com Ernest K. Nielsen, Esq. Washoe County Senior Law Project 1155 E. Ninth Street Reno, NV 89512 enielseni§ashoecounty. us Wiliam Bible Nevad Resort Association 3773 Howard Hughes Parkway, Ste. 320 N Las Vegas, NV 89109 bbible(gnevadaresons.org E. Leif Reid, Esq. Lewis and Roca LLP 5335 Kietze Lane, Suite 220 Reno, NV 89511 Jreidi§lrlaw.com Sleven D. Kång, Asst. City Attorney City of Fallon P.O. Box 1203 Fallon, NY 89407 ::ODMA \PCDOCS\HLRNODOCS\566670\1 Page 1 of2 i 2 3 4 5 6 7 8 9 '2 10\'o ~ ~ Po 11 :I 20 "0 'Ell'12~CI~tI.,tl 5 4) ~13 .¡e ~ ~l:HI.Z 14 Æ.§ ~ 15,.;:Öl) ...o~ i:ø. .. 0 16u ~ ~ ã ¡; ü 17.. t"or-'; I'18:: 19 20 21 22 23 24 25 26 27 28 Bil Kockenmeister, Esq. P.O. Box 71583 Reno, NV 89570 Ibdask6~char.net Marha 1. Ashcraf, Esq. Lewis and Roca LLP 3993 Howard Hughes Parkway, Ste. 600 Las Vegas, NV 89169 Mashcraf~lrlaw.com Douglas Davie Wellhead Electric Company 650 Bercut Drive, Ste. C Sacraento, CA 95814 Patrick V. Fagan, Esq. P.O. Box 646 Carson City, NV 89702 pfaga~allisonmackenzie.com Donald Bookhyser, Esq. Alcanta & Kahl 1300 SW Fift, Ste. 1750 Portland, OR 97201 deb~a.klaw.com Ellen Allman Caithness Operating Company LLC 9790 Gateway Dr. #220 Reno, NV 8951 i David Lloyd Saguaro Power Company, L.P. c/o NRG Energy, Inc. 1819 Aston Ave., Suite 105 Carlsbad, CA 92008 Michael J. Bertrand, CPA Energy Control Systems, Inc. 50 1 S. Carson Street, 8te. 206 Carson City, NV 89701 Mark Russell, General Counsel Mirage Hotel and Casino 3400 Las Vegas Blvd. South Las Vegas, NY 89109 Chip Little Mirat Americas, Inc. 1155 Perimeter Center West Atlanta, GA 30338 Mo Klefeker Las Vegas Cogeneration II, LLC 350 Indiana St., Suite 400 Golden, CO 80401 Scott Carer LS Power Development LLC Two Tower Center, 20th Floor East Bruswick, N.J. 08816 DATED this 13th day of September, 2006._~.~~:J An employee of HALE LANE PEEK DENNISON AND HOWARD ::ODMA \PCDOS\HLRNODOS\S 66670\1 Page 2 of2 , BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA 2 3 o C.~ ~ 4 Investigation to analyze the stengths and weakesses) of marginal cost of service studies, embedded cost ) 5 of service studies, the reconcilation process and ) how they impact rate classes. )6 )Dkt. 06-05007 ~j . .:i :"_:1 v., 7 8 9 ~ 0 10 SOUTHERN NEV ADA WATER AUTHORITY ("SNW A"), puruat to NAC chapter 703~o £ ~ Õ 1 1 and the Request for Comments in this docket dated May 31, 2006, hereby submits its Reply Comments... '" '5 ~ ~ 12 to the Public Utilties Commission of Nevada ("Commission") regarding cost of service 0= t'o ~ 13 th d i .ø me 0 0 ogies. 'â~£ ~ .~ i 14 Sumar Conclusions t E Õ 15 The July 17, 2006 opening comments of Nevada Power Company ("NPC") and Sierr Pacifico~ = ~ t; S 16 Power Company ("Sierra"), the Bureau of Consumer Protection, PUCN Staf, and Southern Nevada 3 ~ U 17 Water Authority regarding marginal and embedded cost of service studies ar in substatial general0'"-;'" 18 t:i agremen . SOUTHERN NEVADA WATER AUTHORITY'S REPLY COMMENTS ON MARGINAL AND EMBEDDED COSTIG PREPARED BY DR. DENIS PESEAU 19 Key conclusions include: 20 1.Marginal costs should continue to be a primar basis for estimating costs and 21 setting rates in Nevada. 22 2.Some type of equi-proportional scaling of marginal costs to revenue 23 requirements should be continued, whether to overal revenue requirement or individual 24 functions. 25 3.The revenue requirement should continue to be fuctionalized prior to marginal 26 cost reconcilation. 27 1111 28 IIII ::ODMA\PDOS\HLRNODOS\555270\1 Page 1 of5 9 ~o 10~o ON ~ iitI 80... I''0 :s 0\ 12 ä CI 00 c: .. ~o Q'O 13fI Q ~ '5 J5 ~ 14 Ö.~ ~ ,l_... 15Q:; UQ ~ i:ø. .. 0 16Q fI ~ 3~u 17 Q I'~ I' 18 19 20 21 4. The use of inverse elasticity to allocate costs has been correctly dismissed by the 2 Commssion in the past due to the lack of credible elasticity studies both for customer classes and 3 demand, energy, and customer cost categories. 4 Differences surfaced with respect to: 5 1.Whether embedded cost of service stdies need to be taken all the way to the 6 individua customer class levels, as opposed to only fuctions. 7 2.Whether or not, and the basis by which, the "next generating unit" afects 8 marginal capacity cost calculations. 3.Whether or not, and the extent to which, margial capacity costs can differ from those of the least costly peakng unit. DISCUSSION A. Usefulness of Embedded Cost Studies The opening comments of SNW A supported the filing of embedded costs broken down to fuctions. The SNW A sees no need to continue such stdies disaggregated and classified to the customer class leveL. There is a theoretical shortcoming of historical embedded cost classification and allocation factors (e.g. maximum, peak and average demands) compared with marginal cost factors. Secondly, embedded cost of service studies taen to the customer class level presume that the historical cost and resoure mix of a utilty provides reasonable prices going forward. The SNW A concludes that the marginal cost of servce studies tyically conducted in Nevada provide superior pricing information to consuers. B."Next Generating Unit" 22 There is some confusion surounding the estimate of generation capacity cost and the "next 23 generating unit" in the utilities' resource plan. This confusion appear to stem from the lack of a 24 careful distinction between "long-ru" and "short-ru" margial costs. 25 Nevada has always adhered principally to Long-Run Incrementa Costs (LRIC). Ths concept 26 is, admittedly, purely a theoretical constrct, full of convenient assumptions (e.g. instataeous 27 adjustment of all factors of production). LRIC is the basis for the peaker method of estimating 28 generation marginal costs and the "NERA Method" used in Nevada. Under ths method, the utilty and ::ODMA\PDOS\HLRNODOS\555270\1 Page 2 of5 5 6 7 8 9 ~o 10~o OM,. 11:i ! 0 i~~ 12 ~ ¡~ 13 'š bi ~ 4) ~Z 14i:.§ ~ ~_... 154) :=U4)~ i: ø... 0 16 u rn ~ 3~u 17 4) to'¡to 18 :i 1 the entire interconnected electrcal grd is assumed to be in perfect equilibrium at all times. In such 2 instaces, with no excesses or shortages of capacity allowed, the marinal cost of capacity mus 3 necessaly be equal to the cost of a peer. This, of coure, holds only because of the convenent 4 assumptions. With no allowance for shortges, excesses, or suboptimal generating unit mixes, marginal capacity costs never depar above or below this peak cost regardless of the cost of the actual next unit planed on the system. All the above conclusions change dratically under margina costing principles tht ar not purely and theoretically "long-ru." Care must be taen not to mix concepts of "long-ru" and shorter- 19 20 21 22 term marginal costs. Under the latter, marginal capacity cost of generation ca move radically upward or downward. Mathematically, shorter-term marginal cost must be modeled carefully with sophisticated capacity expansion and production cost models. Under such circumstaces, the actua operating circumstances of the utility determine the marginal capacity cost. In such cases, the fuel savings by actual more effcient new plants can be a credit or offset to capacity cost potentially resulting in marginal capacity costs lower than a peer. Or, conversely, in times of regional capacity shortages, brown-outs and black-outs give rise to so-called "sbortge costs" of capacity that can greatly exceed the marginal cost of a peaker. Ths potential for wide swngs in marginal capacity costs, and reulting swings in customer- class revenue requirements, has led may state regulatory jursdictions, including Nevada, to remain with the long ru incremental or marginal costing methods. CONCLUSION The SNW A addresses the followig, more speific, remarks of other paries: 1.The Companes' conclusion is correct that the marginal cost of generation, 23 under Nevada's application oflong ru marginal costs, is not infuenced by the next unt to be 24 built. (Sierrevada opening comments, p. 4, lines 2-16) 25 2.The Companies' arguments that there is a logical consistncy in separtely 26 reconcilng distrbution marginal costs, but lumping into one category an remaining cost, is 28 1111 27 incorrect. While the SNW A does not in ths case oppose the Companes' proposal, the issue of ::ODMA\PDOS\HLRNODOS\SSS270\1 Page 3 of5 2 3 4 5 6 7 8 9 io 10 ~oOM_11:i ! 0... l''0 =i 0\12 ã r/ 00 ~ If.g 132 ~ ii 'ä ~r/ Ž 14 ~.3~15~_...G):= UG) ~ ~ i:.. 0 16G) :l ; 5~U 17i- l' G) l' -; l'18:i 19 20 21 22 23 24 25 26 27 28 reconcilng unbundled functionalized costs should be made on a case-by-case basis as a mean to avoid unntentional subsidies. (p. 3, lines 8-24) As a general matter, the reconciling of costs according to the tota of all fuctions wil best reflect marginal costs. The reconcilng of costs according to individua functions better reflects embedded costs. 3. The BCP's coinents regarding the netting of fuel savings and/or market price from the cost of a peakng unit (p. 3) is not appropriate under Nevada's purely long ru costing. When we assume that all generation is always in exact equilibrium, there can be no additional fuel savings or market price discrepancies. 4. The discussion of Hoover B is not appropriate for reconcilng marginal costs. Hoover B power is the cheapest resource on Nevada Power's system and therefore would never be on the margin or influence the marginal cost study. RESPECTFLLY SUBMITTD ths 31 st day of July, 2006. BY:0~~ FRED SCHMIDT Hale Lane Peek Dennson and Howard 777 Eas Wiliam Street, Suite 200 Carson City, NV 89701 (775) 684-6000 and CHAES K. HAUSER General Counsel, SNW A 1001 S. Valley View Blvd. Las Vegas, NV 89153 (702) 258-7167 Attorneys for the SOUTHERN NEVADA WATER AUTHORITY ::ODMA\PDOS\LRNODOSS270\1 Page 4 of5 ".. , I' ,. # 1 2 3 4 5 ,6 7 8 9 ~o 10 ~OON..11:i 20... t" ä =s 01 12fI 00 i= i ~13o ti '9 ti ~fI u u ~Z 14 Q...i 15.!-'"u:: 0u ~ i= ø... 0 16u :a ~ ã Ji 0 17~ t" U t" i; t"18:i 19 20 21 22 23 24 25 26 27 28 PROOF OF SERVICE I hereby certfy that I mailed the foregoing Southern Nevada Water Authority's Reply Comments on Marginal and embedded Costing in Docket 06-05007 by delivering via U.S.P.S. copies thereof, properly addressed for mailing to the following persons: . Louise Uttinger, Assistant Sta Counsel Public Utilties Commission of Nevada 1150 E. Willam Street Carson City, NV 89701-3109 uttingeg~puc.state.nv .US Wiliam Staley Senior Deputy Attorney General Bureau of Consumer Protection 100 N. Caron Street Carson City, NV 89701-4717 wbstane~ag.state.nv.us Dated ths 31st day of July, 2006. ::ODMA\PDO\HLRNODOS\55270\J Alaina Burenshaw Public Utilities Commssion 101 Convention Center Dr., #250 Las Vegas, NY 89109 aburens~puc.stte.nv.us Elizbeth Ellot Assistt Sta Counsel Nevada Power Company/SPPCo. 6100 Neil Road Reno, NY 8951 1 bemot~pc.com . ;¿.~. ~ C ,,:U t ~ Ú' ¿¿t/~ Teresa A. Wiliams Page 5 of5 ~3 __..&á..J 2 3 4 5 6 7 8 9 ~10ao~OON..11:i B 0... t-~ :: 0\12 ä ui 00i:JI'o I)~13II I) i'...:: ~ ã ui I)14I) ~ZO...~ 15~_...I)~UI)~ i: Q. .. 0 16I) :a II ä ui ~17.. t- UI) f' -; f'18:i 19 20 21 22 23 24 25 26 27 28 BEFORE THE PUBIJIC UTILITIES COMMISSION OF NEVADA n C:¡ic. Investigation to analyze the strengts and weakesses) of marginal cost of service studies, embedded cost ) of service studies, the reconciliation process and ) how they impact rate classes. ) ) SOUTHERN NEVADA WATER AUTHORITY'S COMMENTS ON MARGINAL AND EMBEDDED COSTING PREPARED BY DR. DENNIS PESEAU Dkt. 06-05007 f....")û SOUTHERN NEVADA WATER AUTHORITY ("SNWA"), pursuat to NAC chapter 703 and the Request for Comments in this docket dated May 25, 2006, hereby submits its Conuents to the Public Utilties Commission of Nevada ("Commission") regarding cost of service methodologies. INTRODUCTION The so-called "Arab oil embargo" of the early 1970s had a dramatic impact on the costs and rates of electrc utilties thoughout the world. In the U.S., ths embargo, and the subsequent ru-up in the prices of most fossil fuels, changed the historical predictabilty of these utilties' grwt rates, costs, and revenue requirements. The changes to the utilties' cost environment and shift to new an vared generation technologies had the effect of heightening utilties', regulators', and cusmers' interests in ratemaking. A major study in 1973 designed to carefuly define cert ratemakng and rate settng principles culminated in the National Association of Reguatory Utilty Commissioners' ("NARUC") publication Electrc Utilty Cost Allocation ManuaL. In subsequent stdies conducted in the mid to late 1 970s, joint efforts of regulators and publicly and prvately owned electrc utilties ("te E~RI studies") resulted in several volumes of costing and ratemaking studies designed to captue the changing and time-differentiated natue of the costs in the electrc utilty industr. These and subsequent studies led many regulatory jursdictions, including Nevada, to begin endorsing rates that were in some degre based on economic or marginal costs. 1/1 ::ODMA\PDOS\HLRNODOS\SS2493\1 Page 1 of7 8 9 ~o 10~o OM..11:i80... l''0 ~ 0\12fJ 00 00 i: .. eio 8 'g 13 '9 b ~l'Z 14 Ö.~~ 15~_...4) :; U 4) ~ i: ~.. 0 16 l ~ ~~U 17l' C) l' -; l'180: 19 20 21 22 23 24 25 26 27 28 1 Enactment of the national Public Utilties Regulatory Policies Act of 1978 ("PURP A") 2 imposed significant new requirements on private utilities to compile and record costs and other data 3 necessar to better set customer rates. 4 Tension Between Embedded and Marginal Cost Rates 5 A peculiar tension has arsen, and remains today, between "accounting costs" and "economic 6 costs" for ratemaking. These terms are often described as rates based on embedded costs compared 7 with rates based on marginal costs. The debate arses initially because of the statutory requirement to begin the ratemakng process with a tota sum of revenues, the revenue requiement that does indeed reflect those costs expected to be incured by the utilty. The revenue requirement will generaly reflect the normal accounting costs, both capital and varable, presently being incured by the utilty. These costs are embedded, that is, averaged over the varous fuel and other expenses, and over varous generating and other investment in place, perhaps adjusted or "normalized" to the test year. These varous costs can then be fuctionalized, classified, and allocated to varous customer classes on the basis of these actu averaged or embedded costs. But, as economists often stress, historical cost-based rates may not provide reasnable customer rates or "price signals." A price signal, it is argued, is necessar to provide incentive for customers to consume according to the cost strctue facing the utility in a going-forward basis, not on where the utilty has been. However, as is made apparent by the issues posed by the Commission for consideration in this docket, estimating forward-looking costs requires, in some cases, signficant depares from past recorded costs, thereby requiring assumptions and forecasts. The comments made here by the Southern Nevada Water Authority do not attempt to define and explain the nuances of the embedded and marginal costing methods, but instead provide a context for the present methods of ratemaking in Nevada and, as a general matter, to encourage a continuance of ratemaking that is closely aligned with valid marginal cost estimates. 1//1 //11 ::ODMA \PCi:\HLRNODOS\552493\1 Page 2 of7 .. 2 3 4 5 6 7 8 9 10 10 i ~oON~11=i~O... l' ä =' 0\12lZ 00 =.. ~g 3 'g 13 '5 b ~lZ 4) 4) äZ 14O...i 15~_...4)~ C)4) = 0... 0 164) in ~ fä ûl C)17,. l' 0) l''; l'18=i 19 20 21 22 23 24 25 26 27 28 A. Functionalizing Marginal and Embedded Costs to Revenue Requirement Functionalizing the tota revenue requirement involves dividing the tota costs into generation, trsmission, and distribution costs or fuctions. Under embedded cost of servce, these fuctions ar largely already prescribed under the FERC Uniform System of Accounts. Since the embedded cost process begins with the allowed revenue requirement, setting customer rates according to these fuctions, although complicated, provides a somewhat stghtforward basis for collecting the prescribed revenue requirement. Marginal cost of service stdies look to the cost of the new or next increments of generating plants, transmission, and voltage-differentiated distrbution servces. The maginal or incremental costs of new generation, transmission, and distrbution will not, in genera, equal the utilty's revenue requirement and therefore wil have to be "reconciled" or scaled upward or downward to equal the revenue requirement. Varous economic theories and models demonstte the superior "effciencies" of having rates reflect the present cost increments of generation, tranission and distbution facilties. The Commission has for decades adopted marginal cost stdies that fuctionaze costs makg up revenue requirement according to marginal cost that ar scaled or reconciled to average or embedded costs. The SNW A strongly endorses ths procedure and recommends that the Commission continue the policy. B. Guidelines for Marginal Generating Unit As discusd above, costs functionalized to genertion will, in a marginal cost study~ be basd upon the next increment of generating facilties. In practice, the "next" generating increment could be a combustion tubine (now usd in Nevada), a combined-cycle facilty, varous typs of coal plants, renewables, and refubishment to existing plants, among others. The significance of the choice of marginal generating unt is largely in the "classification" of generation costs into demand (capacity) and energy. And, because different customer classes have different usage patterns, or "load factors", different classifications of relative demand and energy costs will bear differently on respective customer classes' share of tota revenue requirements. 1111 ::ODMA\PDOLRNODO\552493\l Page 3 of7 ._--~ -~~- - 1 2 3 4 5 6 7 8 9 ~o 10~oON..11:i So... t" ä :: 0\12Cf 00 i: .:.ao u 13(4 ß Ø$.§ ~Cf Ž 14 Ö.~~ 15 lE3D~~ i: 16.. 0u :a Ð ; ii u 17~ r-u r-ì 'i t"18I :i 19 20 21 22 23 24 25 26 27 28 For nearly the decades ths Commission has adopted the "NERA Method" of selecting the marinal generating unit. Ths method essentially assumes that. in equilbrium, the next generating unit wil be a natual gas-fired combusion turbine. Thus, generation costs have ben classified in Nevada to demand and energy on the basis of the relative capacity and energy costs of a combuson turbine. Larger, more effcient generation technologies generally have a higher capacity or demand cost component than does a combusion tubine, but are more fuel effcient (have a lower heat rate), therby resulting in fuel savings over which the higher additional capacity costs ca be jusfied. Linear and similar mathematical programng models have been developed to more precisely assess the economics of what actuly should be the "next or incrementa generation unit." The only advantage of using the NERA Method is that it is relatively simple to compute and is arguably accurate enough for ratemaking. Given the contiuing rapid growt of both Nevada utilties, it may be wortwhile to consider or fuer study other available methods more consistent with the specific resource charcteristics and load baances of Nevada's utilties. Many improvements are now available that allow more precise choices of "the next" generating unt. However, the modeling effort in such estimates become more ~omplicated and may not be wort the effort. The SNW A is available to elaborate on th issue in upcoming workshops. For the present, the SNW A contiues to support the pas Commission decisions to base rates on the cost classification resulting from a combustion turine marginal unt. C. Using Margina Cost of Servce to Set General Rates As it has in the past, the Commission should continue to base cusomer class rates on marginal costs. Marginal cost-based rates provide a clear, but not exact, direction for providing appropriate cost responsibilty and price signals for making consumption decisions and investents in energy effcient equipment. Marginal cost-basd rates also provide the Commission with a meas of how equitable are the relative cusomer class rates. When compared with respective costs, class rates allow identification and grdua elimination of interclass subsidies. Marginal cost-based rates also provide the means by which costs can be seasonally differentiated. Moving toward seasonally-differentiated BTER rates, for example, would reduce or eliminate the need for Nevada electric utilities to finance the BTER sumer revenue shortfalls caused :;ODMA\PDOS\LRNODOS\5S2493\I Page 4 of7 _. ~o 10 ~oON_11:ieO... t" 1 =i 0\12fI 00 i: ..: as o Ð "0 13VJ Ð as 'ä ~ ~fI 4) 4) ij Z 14 A...~ 15..-...Ð:: UÐ~ i:ø. .. 0 16Ð VJ ~ ã as as~~U 17 4) t" O; t"18:: 19 20 21 22 23 24 25 26 27 28 by the present averaging of the high summer fuel and purchasd power costs with the lower non- 2 sumer fuel and purchased power costs. The SNW A raised this issue in Nevada Power's recent 3 DEAA case, Docket 06-01016, and the Company proposed that the issue be fuher reviewed outside 4 of a DEAA proceeding. 5 Nevada Power's BTER marginal costs have been shown to var signficantly by season. These 6 costs should, therefore, be reflected in seasonal rates for purses of equity, effciency; and price 7 signals. Appropriate seasonalization of the BTER would also reuce anomalies from the averge 8 BTER, including the need in certn instances to chage negative BTER rates to some classes because 9 the BTER to these same classes were set too high. D. Filing of Embedded Cost Stuies in the Genera Rate Case (GRC) A filing of a detailed embeded cost study as support for the present Statement 0 cost studies filed in a general rate case could be very usefuL. Presently, the functionalized marinal costs ar reflected in tn.e Companies' Statement O. However, the comparable fuctionalized embeded costs, from which the reconciled costs are derived, are not directly available. Including this aspect of embedded cost results in each genera rate cas could provide a basis for checking the reasonableness of the utilty's embedded cost allocations. E. Usefulness of Embeded Cost Study Embedded cost studies could be usful to reconcile marginal costs back to the overall genera revenue requirement of the utilties. Furermore, the embedded costs studies could indicate the reasonableness or not of the utilities' functionalization and classification of the actual average or test year costs. 1111 1111 1111 //1/ ::ODMA \PDOS\HLRNODOS\SS2493\1 Page 5 of7 2 3 4 5 6 7 8 9 ~o 10 ~o o C' ..11:i 80... l'"0 :: 0\12~ CI 00 i:"' ~ o 0 "0 13fI 0 ~.~ b ~ CI u o äZ 14 Q...~ 15~_... S:: ÜØo ~ i:.. 0 16o II ~ä~ü 17~ l' U l' ¡; l'18=i 19 20 21 22 23 24 25 26 27 28 CONCLUSION SNW A continues to support the use of marginal costs in deriving the actul rates of customer classes. As explained above, SNW A also believes there may be some value in having Nevada's utilities develop and present embedded cost studies as a means of comparson. SNWA is interested in continuing to paricipate in ths docket and requests that it be added to the servce list. RESPECTFULLY SUBMITTED ths 17th day of July, 2006. BY:~~~ FRED SCHMIDT Hale Lae Peek Dennson and Howard 777 Eat Wiliam Street, Suite 200 Carson City, NV 89701 (775) 684-6000 and CHAES K. HAUSER Genera Counsel, SNW A 1001 S. Valley View Blvd. La Vegas, NV 89153 (702) 258-7167 Attorneys for the SOUTHERN NEVADA WATER AUTHORITY ::ODMA\PDOS\HLRNODOS\552493\1 Page 6 of7 .. 2 3 4 5 6 7 8 9 ~o 10 ~ooM_11::!o..... 1 :i 0\12fi 00 d tf.a 13-p~fiŽ 14 CL~ r; 15..-'"o::Uu~ d ii +- 0 16u fI Sâ~u 17.. ..0.. õ1..18:: 19 20 21 22 23 24 25 26 27 28 PROOF OF SERVICE I hereby certify that I mailed the foregoing Southern Nevada Water Authority's Comments on Marginal and embedded Costing in Docket 06-05007 by deliverng via U.S.P.S. copies thereof, properly addressed for mailing to the following persons: Sta Counsel Public Utilities Commission of Nevada 1 150 E. Wiliam Street Caon City, NV 89701-3109 Eric Witkoski, Consumer Advocate Bureau of Consumer Protection 100 N. Carson Street Carson City, NV 89701-4717 epwitkos(gag.stte.nv.us Dated this 17th day of July, 2006. Alaia Burenshaw Public Utilties Commission 101 Convention Center Dr., #250 Las Vegas, NV 89109 aburens(gpuc.state.nv. us ~ó~"n · ")d_.ILML,mlt Teresa A. Wiliams ::ODMA\POO\HLRNODOS\SS2493\I Page 7 of7 ,. 1, y ..~.e . Investigation to review processes, theories and methodologies that may be used to establish just and reasonable rates in general rate cases. BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA C~R~O~ g/v ~F~,8 NOV - 22005 DEN~~~~ ~t~DE HPEEI(v aWARD ) ) Docket No. 05-7048 ) ) ) SOUTERN NEV ADA WATER AUTHORI'S COMMENTS REGARING RATE MAKG MECHANISMS SOUTHERN NEVADA WATER AUTHORITY ("SNW A''), puruant to NAC chapter 703 and the Request for Comments in this docket dated August 26, 2005, hereby submits its Comments to the Public Utilities Commssion of Nevada ("Commission'') regarding processes, theories, and methodologies that may be used to establish just and reasonable rates in genera rate cases puruant to Section 7 of Senate Bil ("S.B'') 238. INTRODUCTON On August 26, 2005, the Public Utilties Commission of Nevada ("Commssion'') requested comments on a number of ratemakg issues, designated as Docket No. 05-7048. The Commission directed the comments to avoid gener discussion of the issues, so the intrduction below is limited and provided solely as a mean to introduce the most common technical points contained in the specific questions rased in the Commission's Request for Comments. The the topics for comment rased by the Commsion address the conceptually simple, but practically more diffcult, task of matchig the utility's likely test year revenues to its likely costs. Properly constrcted, either an adjusted, normalized historical test year or a near-ter future test year can be equally effective as a mean to match costs and revenues over the penod in which rates are to be in effect. Factors afecting the accurcy of either adjusted historical or futue test year ar: . Precision of the baseline or benchmark cost and revenue inormation; . Precision of the assumptions pertaining to cusomer grwt, investment grwt, load growth and the incremental cost strctue and revenues associated with each; and · Precision of and the lengt of projections or forecasts for individual cost and revenue categories. C:\oUME-I\mitchclI\LOCALSI\Templnote523F4B\-137764.00Page i of 6 ,. ~ ;/ 5 6 7 8 9 10 10~O OM.. 11:i B 0... l''Ø :: 0\ 12 få 00 00c .. lI .å 11 13~ fI Ž 14 Q.§~ ..-... 15o=uo~ c ø... 0 16u :3 a !~u 17o l'';l' 18 :i e . 1 2 3 4 COMMENTS ON SPECIFIC COMMISSION TOPICS 1.Ratemaking mechanisms that wil allow for the consideration of customer growth, infrastructure growth and load growth during periods when rates are to be in effect Ratemaking mechansms to deal with these issues reuire a distinction between fixed and varable costs. Fixed costs and the reovery of them in the face of customer, investment, and load grwth reuire the estimation of marginal or incremental costs and comparson of same to revenues. Varable costs require considertion of a mechansm capable of varng or at least trking and accounting for these costs independently of customer, investment and load grwt. The following points discuss this distinction and the fact that the Commission over time has dealt well with these challenges. . Use of a futur test perod for setting base tarff energy rate ("BTER'l costs and use of deferred accounting for fuel and purchased power costs is suffcient to deal with grwth in fuel and purchased power costs durng the period when rates are to be in effect. No other mechanism is necessar for that major rate component. . Mechansms to deal with cost and rae components, other than fuel and purchased power, are only necessar if incremental cost is grater than increental revenue for customer and load growt investment durng the period rates will be in effect. If incremental cost is close to increental revenue, then growt wil generate suffcient revenues to offset the non-fuel and 19 purchased power costs caused by customer and load. growt. The evidence for Nevada 20 suggests that incremental cost is not suffciently grater than incremental revenue so as to cause 21 any major earngs shortfalls for Nevada Power. In fact, the Commission aleady minimizes 22 the chance of this occurng by allowing the use of an end-of-period rate base and a subsequent 23 cerfication perod for updating revenue requirement. 24 . Even though incremental revenue and cost may be reasonably close for normal rate base and 25 expense increases caused by growt, the lumpy natu of some utilty investments such as 26 major power plant, transmission lines, and substation additions may cause futue revenue to fall 27 short of the incremental revenue requirement associated with futue rate base additions. Those 28 unque types of capital additions are easily identified and able to be mitigated by such vehicles C:\OOUME-I\michcll\LOCALS-l\em\iote23F4B\-137764.00Page 2 of 6 ".,?/ to 10~oON..11::!o... r- 1 ::0\12CI 00 i= .." (io 4) 't 13II ~ m j ~CI Ž 14Ö.l~ 15.!-'"4):: U æ~ i:16.. 04) =; 5~U 17Io r- 4) t- -; r-18:: 19 20 21 22 23 24 25 26 27 28 e . as AFC, CWIP, recording of regulatory assets, etc. These mechanisms have been used by 2 the Commission in the past when unusual and large capital additions are under constnction but 3 not yet providing service to ratepayer. 4 · If the Commission detennines that additional measures are necessar to alleviate the potential 5 problems of growth, the Commission could also consider a fonn of deferrd accounting and 6 cost recovery for cost shortfalls for major investments so that the cost of delay in recovery can 7 be reognzed. 8 2.Mechanisms by which the State of Nevada can transition away from the historical 9 test year for purposes of ratemaking. · The State of Nevada has in place a number of policies that provide means to avoid the staleness of purly historical test year. The question is whether these measurs are adequate in light of customer grwt, cost escalation and general inflation. A major advantage of using a historical test year as an initial point of depare and reference is that the costs and revenues are known and measurle. Trasitioning to a fully futue test year relaces known and measurble data for predictions of costs and revenues. Ths raises a whole rage of challenges includig the ådditional step of prearng foreasts of all test year cost and revenue components for revenue requirement detennination, and the issue of how forecas mayor may not be used in customer class cost allocation and rate design. Ths increes the rate case parcipation costs of all paries necessar to evaluate the predictions of test year costs and revenues. In addition, it increases the number of contested issues in rate cases because of use of predictions rather than actual data. · Whle it may seem that matching costs and revenues for the period rates will be in effect is extremely desirable, it is not always a necessar condition. In fact, if unt costs ar reasonably constant, rates set using an adjusted historical test year will be nearly identical to rates based on a future test year. In such a case, use of a historical test year will not cause earings shortfalls. C:\OUME-I \mitehcIiLOALSl\em\i0te23F4B\-13n64.ooPage 3 of 6 .// 4 5 6 7 8 9 ~o 10~o ON.- 11=.80'g'a~ i' II 00 12 c .. el i ~~ 13.§~ ~ I) i:Z 14t:U~ ~u-... 15 'û:= UI)~ cAt.. 0 16o fI S j~u 17 or-~ r- 18 19 20 21 22 23 24 25 26 27 28 .. 1 Only mismatches between incremental cpst and incremental revenue cause shortalls. i And, while updated incremental generation, transnlission and distrbution system. cost studies are always necessar, past experience in Nevada has not identified a signficant mismatch between 2 3 incremental cost and revenue. · The desire result of using actual cost and revenue data and allowing a reasonable opportnity to ear the allowed rate of retu can be accomplished with adjusted historic number. Known, measurable, and reasonably estimable rate base additions and expense changes can be easily reognzed without resorting to use of a full futue test year. This is often accomplished by using known and measurble costs with out of period adjustments. Revenue requireent impacts of major rate base additions and expense changes that can be predicted with a high degree of certy can be pro formed into test year revenue requirement to reduce the chance of earngs shortfalls. The State of Idaho handles such matters with out of perod adjustments. The State of Iowa also uses a hybrid approach that begins with a historical test yea and makes adjustments for cerai major events predicted to occur afer the test period. 3. Examples of future test year and/or other forward-looking rate making mechanisms. · The State of Idaho's use of out of perod adjustment for reasonable known and measurable major rate base and expense changes has. already been refernced above. Idaho incorporates into the historical test year results of operations, the estmated rate base and expense changes of significant and known item for a perod beyond the end of the test year. Idao also requires utilties to include revenue generating and expense reducing elements in test year results when utilties elect to include out of period adjustments in rate cases. · A reent surey conducted for presentation to the Iowa Utilties Board indicated that approximately 30 states use a historical test period and an additional six sttes use a hybrid approach beginning with a historical perod, but allowing adjustments with futue, predicted i For exale, iflast year a business produced io unts at a cost, includig reasonale profit, of$IOO an on tht basis decided to chae $10 per unt for next yea, it would not suffer any shortalls if the incrementa cost ofadditiona unts was $10, the same as last year. If it sold IS unts in the year, it would generte revenes of$150 and incur costs of $ i 50. Ony if the incremental costs were substatially greater than $10 per unt would it suffer shortalls. ~=-=~~~.ii:";;l'Il~~~:T ~...:,:u ""_- ""- _"" ~--.. ~. .._""~.-'"_=~~~""''=..=-'"'~=''_o:~''~ _~~~c~_=.._==-", ~~ =-i; ~~..__"'. ~"""'-;""~"' "oj"'~_~"~~__="",~=,,;r~ ""'' C:\OUME-I \iitchell\LOCALSl\emp\noteS23F4BH 37764,ooPage 4 of 6 ./". 2 3 4 5 6 7 8 9 ~o 10~o OM..11:iSO... t" ä :i 0\1200 00 i: tf.a 13o u as.~ b ~00 I) u ~Z 14 O...~ 15,: _...1):- UI)~ i: Øo .. 0 16 § ~ S~~U 17 u t"~ t"18 19 20 21 22 23 24 25 26 27 28 .. information. A copy of the report, which was prepared by the Iowa Utilities Board in response to a request from its state legislatue, is atthed as Exhibit A. · If the Commission determines that it is appropriate to consider events occurng during the period when rates wil be in effect, the SNW A recommends tht rather than beginning with fully forecasted data and results of opertions, that known and measurable data frm a historical period should be the basis for establishing benchmark cost and revenue data. Historical test year data could then be adjusted for major. known and accurately predictable near future events such as is done in Idaho and Iowa and sever other states that use a hybrid test year. RESPECTFLY SUBMITD this 31st da , BY: T Hale Lae P Denson and Howard 777 East Wiliam Street, Suite 200 Caron City, NY 89701 (775) 684-6000Attomeyfor SOUTRN NEVADA WATER AUTORITY C:\oUME-l\iitehell\LOCAlS-l\em\note523F4B\-1377646.00Page 5 of 6 ~=~"""'~~~_-~,."' '" ~"" "~,:.~..~="o~,,~_ __., ~""-.-~~ß::i.,,,_._..~ """"'"_.~~~""_~=~~~='~..~m: .:~=-..-. ~~~_~~ _--__""-. ,_~ ~_ -= "'::_""_-: ~-:_""_~___""--~ - :~ '. V ..,, # 1 2 3 4 5 6 7 8 9 io 10 ~oON_11:iSo... t" 1 =i 0\12en 00 c: J' tUo Bog 13.~ b ;.en ~14 ~.! '-15.l-'"g:-U ~ ~ c:16.. 0o fI 5 ãuJu 17~t"o t" ãš t"is:i 19 20 21 22 23 24 25 26 27 28 PROOF OF SERVICE I hereby certify that I mailed the foregoing Southern Nevada Water Authority's Comments Regarding Rate Making Mechanisms in Docket 05-7048 by delivering via U.S.P .S. copies thereof, properly addressed for mailing to the following perns: Staf Cowiel Public Utilties Commission of Nevada 1150 E. Wiliam Street Caron City, NY 89701-3109 Alaia Burenshaw Public Utilties Comission 101 Convention Center Drve, Suite 250 Las Vegas, NY 89109 Adriana Escobar-Chanos, Consumer Advocate Bureau of Consumer Protection 555 E. Washington Ave., Suite 3900 Las Vegas, NY 89101 Collee Rice Nevada Power Company 6226 West Sahar Avenue Las Vegas, Nevad 8915i Dated this 31st day of October, 2005. V:\LEOAL\Pblic Serice Conssoi\Dket OS-7048\ComlS.ooPage 6 of 6 '0 10~o~oON~11:i 20... f"'0 ;: 0\12 ã C/ 00i:.¡t'13o It '0iI It t'....l ~i: C/ Iti: Z 14 ö.ff ~ 15~_...It:;Uit~ i: ø. .. 0 16It iI iI ã~ ~17~ f" UIt f" C; f"18:i 19 20 21 22 23 24 25 26 27 28 I 2 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA 3 Investigation to review processes, theories and methodologies that may be used to 4 establish just and reasonable rates in general rate cases. 5 6 7 ) ) Docket No. 05-7048 ) ) ) SOUTHERN NEVADA WATER AUTHORITY'S SUPPLEMENTAL COMMENTS REGARDING RATE MAKING MECHANISMS 8 SOUTHERN NEV ADA WATER AUTHORITY ("SNW A"), pursuant to NAC chapter 703 9 and the Request for Comments in this docket dated December 15, 2005, hereby submits its Supplemental Comments to the Public Utilties Commission of Nevada ("Commission") regarding processes, theories, and methodologies that may be used to establish just and reasonable rates in general rate cases pursuant to Section 7 of Senate Bil ("S.B") 238. INTRODUCTION The Commission's proactive assessment of alternative ratemakng mechansms is timely in light of Sierra Pacific Resources recent anouncement of its planed $3 bilion investment in new generation and transmission facilties, in addition to the recent purchases of the Silverhawk and Lenzie plants in southern Nevada, and the Tracy Combined Cycle Project planed in northern Nevada. In light of these planed investments, the challenge facing the Commission is to continue practices that most accurately balance the utilities' revenues and costs over the period in which rates are to be in effect. After decades of meeting astonishing growth, primarly through outside power purchases, the electric utilities, paricularly Nevada Power Company, propose to more than double rate base and transition to principally generating operating companies over the next few years. Thus, a reassessment of the processes, theories, and methodologies currently used in Nevada is timely. COMMENTS ON SPECIFIC COMMISSION TOPICS In its comments of October 3 i, 2005 in this docket, the SNW A stressed the importance of distinguishing between fixed and variable cost considerations when assessing any of the alternative test year ratemaking mechanisms (see SNWA, p. 2-3, 1. 7). The utilties' ratio of fixed to varable costs appears as if it may change dramatically in the near future. For puroses of ensurng cost II. http://e26,cm::il.excite,corrJviewer.php/?m=O&mid=3336&p=2 Page 1 of8 1 2 3 4 5 6 7 8 9 '0 10i; 0~o o C' .-11:i2o... l"§ :: Ct 12r¡ 00 d õft~13o G) t' .~ J: ~ ã r¡ G)14G) 8 ZO.~~ 15.. .- ...G):: UG) ~ d ø. .. 0 16G) fI ~ ~~U 17~ l" G) l"~ l"18:i 19 20 21 22 23 24 25 26 27 28 recovery of varable costs in an accurate and timely maner, the SNW A continues to support the present DEAA mechanism. The specific comments below pertaining to the four alternatives posed by the Commission in the second Request for Comments in this docket dated December 15, 2005 are, therefore, primarily aimed at fixed cost, general rate case considerations. With regard to the four alternative ratemaking methodologies identified by the Commission, SNW A offers the following observations: i. Alternative I: Full future test year a. This methodology has the potential to reflect growth in cost of service, but is also most likely to misrepresent cost of service because of the need to forecast every element of rate base, expenses and load, and the resulting uncertainty. Improvement in accuracy is uncertain and unlikely. b. Ths alternative is the least cost effective because of the need for all paries to forecast and evaluate every component of cost of service and load. Increased cost and effort does not necessarily increase effectiveness because of the anticipated increased uncertainty resulting from forecast error. Empirical evidence regarding the accuracy of key varables such as interest rates and prices is not encouraging. c. Ths methodology increases the burden and imposes a fiscal impact on state and local agencies (including SNWA and others) because of the need to fully evaluate all forecast components of the futue test period. This methodology also necessitates paricipation in extensive legislative and administrative proceedings required to develop the new methodology. We also anticipate increased electric rates for state and local agencies from the first application due to the uncertainty referred to above. d. A full futue test year requires the most changes in procedures and mechanisms because of the need for a totally new ratemaking mechanism and the need for more thorough analysis of all rate case elements and forecasts. II. Alternative 2: Adjust i 2 month historic test year for known and measurable data up to 7 months forward. a. This methodology has the potential to reflect growth because of adjustment for 7 month of I htp://e26,em:lil,excite,ccllJviewer,phpÌ?m''O&mid''3336&p"'i Page 2of8 I 2 3 4 5 6 7 8 9 "è 10~o~o o C' ..11~2o... f""è = 0\12 ã 00 00= ..~ t' o V"è 131' V t'... i: ~ ã 00 v 14v ~Z0... ~ 15 III..!.. ...v:= Uv~ = ~.. 0 16v 1' ~ã~u 17~ f" V f" '; f"18~ 19 20 21 22 23 24 25 26 27 28 ~ ?\ vdata beyond the fiing date for known and measurable items. This methodology is ()less likely to misrepresent cost of service than Alternative 1 because it is based on 12 months of actual data which will reduce uncertainty. b. This alternative is generally cost effective because it is based on current and known methods with a requirement to only analyze reasonably known and measurable changes for 7 months beyond the fiing date. c. This methodology is least likely to have any major impact on state and local agencies because of minimal changes from curent ratemaking mechanisms. The mechanism merely updates the curent certification process by several additional months. d. Since this alternative is similar to curent ratemakng with minimal changes it would require few changes in procedures and mechansms. The most obvious problem would be the need to identify new procedures for the timing of the updated information related to the discovery and hearng schedule. Some additional standards would have to be developed to determine what is reasonably known and measurable but yet to be experienced data.l\. Alternative 3: Adjust 12 month historic test year for known and measurable data for the period ~ ï ,~ when rates are in effect.?~a. This methodology also has the potential to reflect growt, but requires less precise ~ .- estimates for adjustments by virte of the indefinite time frame for" . . . the period rates are in effect." The more distant the time frame, the more likely there will be a cost/revenue discrepancy either for shareholders or customers. If the interval between rate case filings is short, this concern lessens. b. This alternative is cost ineffective compared with Alternatives 2 and 4, but is probably more cost effective than Alternative 1. c. The cost impact on state and local agencies is likely to be less than Alternative i because the uncertainty of solely future forecasts are tempered with a base of historic information. However, the need to review and evaluate a full historic period and a full futue period may be more costly for review and will clearly increase costs for rate case paricipation over Alternative 2. Page 3 of-8'.", ..1 i http://e26,e:n::il.excite,com/viewer,phpl?m=O&mid''3336&p=i r-- I 2 3 4 5 6 7 8 9 '0 10~o~o ON i-11tt 20 '8 l' ä r¡ ~12 i: io~ el£ 3~13.§ b ~r¡ II II eZ 14 O.~~ 15~ i-... 1I:: ÜII~ i: jl io 0 16II fI ~ã~ü 17i-l' II l' i; l'18tt 19 20 21 22 23 24 25 26 27 28 1111 d. This alternative requires some additional framework and guidelines to determine the "period rates are in effect" (i.e. which portion of the one or two years rates remain in effect) and how to identify futue data which is "reasonably known and measurable". iv. Alternative 4: Most recent 12 months with adjustments up to period rates in effect. a-d. The SNW A's comments on this methodology are the same as for Alternative 2 above. Although this method is called a "historic test year" and Alternative 2 is called a "future test year", the alternative methodologies are identical in the Commission's notice~ Alternative 2 calls for adjustments up to seven months beyond the filing date which, given the suspension period of 2 i 0 days now contained at NRS 704. 110, is the same period as the point up toC V/when new rates will be placed into effect as described in Alternative 4. If the ~mmssion intended to solicit comments on another period different from Alternative 2, SNW A will be glad to provide additional comments at the workshop on Februar 7, 2006. In response to topic 2 requesting an opinion on the legislation, procedures, and mechansms necessar to authorize and implement the alternative ratemakng methodology alternatives, the SNW A offers the following general opinions. SNW A has not offered specific statutory or regulation languge for any of the above alternatives at this point in the proceeding because SNW A prefers the status quo methodology which has been in place for a substantial period of time and requires no changes to curent law. If the Commission does adopt any of the alterntives above (except for Alternative 2 applied to natural gas utilties, given the statutory change already adopted by the 2005 Nevada Legislatue in S.B. 256), NRS 704. 110 must be rewrtten because it curently limits utilties to an historic test period which may only be updated with information up to six months afer the end of that period. If any form of future test year is desired, a substantial rewrte of NRS 704.110 will be required. If only an update to the historic period is made several months beyond the curent system or up to the time rates take effect, then only a smaller revision to NRS 704.110, as it curently reads, is required. If any of the alternatives identified by the Commission in ths docket are to be implemented, a lengty rulemaking to rewrite the schedules and filing requirements in NAC Chapter 703.2201, et seq. will be necessar. http://~26.-cmail.excite;ccwJviewer.php/?m-~&mid-~3336&p~2 Page 4.of8 I 2 3 4 5 6 7 8 9 ~o 10 ~o ON 1" 11ti~O... t" '0 :: 01 12§ lZ 00 d ~~ ei00'0 13I' 0 ei,,, b ~ ã lZ 0 14o SZ ci.:g ~ 15,.1" ...o;'üo~ dø. ~ 0 16o ti ti§ ei ~~~ü 17 o t"~ t"18ti 19 20 21 22 23 24 CONCLUSION Growth has the potential to complicate the effort to set rates that accurately reflect cost of service. As discussed in more detail in the prior SNW A comments, the relationship between 5generation and transmission incremental costs and incremental revenues (rates) determine.. whether growth is revenue or cost enhancing. The chances of this happening' in Nevada may be reduced because of the use of essentially a futue test period for fuel costs. For example, it is clear from recent DEAA filings that use of a future test year doesn't necessarily reflect futue cost of service, otherwse DEAA balances would be small, which they are not. We should not assume that a more " extended future test year applied in a general rate proceeding will accommodate growth and more accurately reflect cost of service simply by basing rates on forecasts of all rate case elements, or that growth will necessarly have a predictable positive or negative impact on earings. In Nevada there is no clear evidence, aside from fuel and purchased power costs (which are already based on a futue test year), that incremental cost is growing considerably more rapidly th incremental revenue. It is not clear at all that rate payers or shareholders would benefit by basing rates on a fully forecasted cost of service because that would dramatically increase all paries' costs of evaluating rate cases and would introduce a great deal more uncertainty in the process which may not even reflect growth any more accurately than an" historic test year. Given the added cost, the greater uncertainty, and the added burden on the process, it seems much more cost effective to begin with the most recent historic test year data available and then make adjustments for major, reasonably known, and measurable rate case elements for a short period of time into the future. This can be accomplished with minimal changes to current processes and procedures, minimal added burden on all rate case paricipants, and at minimal added costs. In addition, since these major known and measurable future events are the most likely to cause futue cost of service to deviate from curent cost of service, growth is adequately accommodated. To the extent that major 25 1/11 26 111/ 27 1/1/ 28 II/I 1.u_,/I_"H: --.;" _.,-;.~ M~/":Q'"Q.nhn/?m='&ml.d~3136&p'''' l l IILLp."L...V."'..IUIi.......'.."".vu..lI '...n..l~pllp/...V - oJ ., ~ Page 5 of 8- ,- I I 2 3 4 5 6 7 8 9 ~10~o~o ONI"11:rU~o 'S l'121 í/ ~d lf~13o 0 ø: .~ Jj :: ã í/ 0 14o SZO.~~ 15~i"'''o:;Uo~ d11 +o 0 16o fI ~ fä ~ U 17~ l'o l'"; l'18= 19 20 21 22 23 24 25 26 27 28 plant additions may fall outside the test year, the electric utilities' should consider the more efficient course of filing timelier rate cases, since they are only obligated to file every two years but are entitled to file more frequently in interim periods if necessar. RESPECTFULL Y SUBMITTED this i 7th day of Januar, 2006. BY: FRED SCHMIDT Hale Lane Peek Dennison and Howard 777 East Wiliam Street, Suite 200 Carson City, NV 89701 (775) 684-6000 Attorney for SOUTHERN NEVADA WATER AUTHORITY n http://e26.emaiLe.-¡cite.comlviewer.phpf?m9l&mid=3336&p=2 Page 6 of& I 1 2 3 4 5 6 7 8 9 '0 10ao~oON .-11~2o... f"'0 :: 0\12 ã ui 00 = .. ~ o Go '0 13f/ Go ~.§ b.. ui Go Go §Z 14 O...~ 15,._... Go:; C)Go~ = ii.. 0 16Go f/ ~ ã ~C)17i- f" Go f" æ f"18 19 20 21 22 23 24 25 26 27 28 PROOF OF SERVICE I hereby certify that I mailed the foregoing Southern Nevada Water Authority's Supplemental Comments Regarding Rate Making Mechanisms in Docket 05-7048 by delivering via U.S.P.S. copies thereof, properly addressed for mailng to the following persons: Staff Counsel Public Utilities Commission of Nevada 1150 E. Wiliam Street Carson City, NV 89701-3109 Alaina Burtenshaw Public Utilties Commission 101 Convention Center Drive, Suite 250 Las Vegas, NV 89 i 09 Ernext Figueroa Bureau of Consumer Protection 555 E. Washington Ave., Suite 3900 Las Vegas, NY 89101 edfiguro~ag.state.nv. us Chad Duval Moss Adams LLP 3121 W. March lane, Ste. 100 Stockton, CA 95219 chad.duval~ossadams.com Conne Silveira Sierr Pacific Power Company 6100 Neil Road Reno, NV 895 i 1 csilveira~sppc.com Dan Foley SBC Nevada Bell General Attorney P.O. Box 11010 645 E. Plumb Lane, Room B 132 Reno, NV 89520 Debra Jacobson Southwest Gas Corp. 5241 Spring Mountain Road Las Vegas, NV 89150 Debra.Jacobson~swgas.com http'/Ie26pmal"I,:Vi"itp ,.nt'/u,¡p'lof,:r ni.n/?l"=".P..t"i.;=1:-i,i:¡:.P,"=~ II . ,fl ~,~. . .._'w. -,~_.." .._.._.ò"",,,.... ~~...." ---~~" - P!lo,, 7 nfR.. -b-'I v.._ . 1 Eric Heath 2 Spnnt of Nevada 330 S. Valley View Boulevard 3 Las Vegas, NV 89107 eric.s.heath~sprint.com 4 Karen Peterson 5 Allison, Mackenzie, et aL. P.O. Box 646 6 Carson City, NV 89702 7 kpeterson~allisonmackenze.com 8 Kathleen Drakulich Kumer Kaempfer, et aL. 9 5250 S. Virginia Street, Suite 220 '0 Reno, NY 89520 ~o 10 kdrakulich~kkbr.com~oON..11 Linda Stinar=20... t- Sprint of Nevada 1 :: Ct 12f/ 00 i= if ~330 S. Valley View Blvd. 04,('13 Las Vegas, NY 89107.~ ~ ~Linda.c.stinar~ail.spnnt.comf/Z 14 Q.§~ 15 Shawn Elicegui .... ...4,::U Lionel Sawyer & Collns4, ~ i= i:.. 0 16 1100 Ban of Amenca Plaza4, rI ~50 W. Liberty Street, Suite 1 100ã~u 17 Reno, NV 89501.. t- 4, t-selicegui~lionelsawyer.com'; t-18= 19 Steve Lubertozzi Sky Ranch Water Service Corp. 20 2235 Sanders Rd. Northbrook, IL 60062 21 22 Timothy Shuba Goodwin Procter LLP 23 901 New York Ave. N.W. Washington, D.C. 20001 24 tshuba~goodwinprocter.com 25 Dated this 17th day of Janua, 2006. 26 27 28 -llhttp://e26,em~i!,e::eite,ec!!!v!e~'!~.PhP!?m=o&mid=3336&;r2 Page,8-£.8 .-...~.,~--_.....___.~;-. .-~iJ. ".-_.,'...,' "._. '_'_ ___. 1. ., 1 2 3 4 5 6 7 8 9 '0 10So~o ON .-11:i 20... ¡. '0 = 0'12 ä lZ 00d"" ('o II '0 13~ II ('... b ~ ã lZ II 14II ijZ0... ~ 15~_...li;'üII~ i: i:.. 0 16II ~ ~ä~ü 17~¡. II ¡. 'a ¡.18:i 19 20 21 22 23 24 25 26 27 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA Investigation to review processes, theories and methodologies that may be used to establish just and reasonable rates in general rate cases.vJ ) ) Docket No. 05-7048 ) ) ) SOUTHERN NEVADA WATER AUTHORITY'S REPLY COMMENTS REGARING RATE MAKIG MECHANISMS SOUTHERN NEVADA WATER AUTHORITY ("SNWA"), pursuant to NAC chapter 703 and the Request for Comments in this docket dated December 15, 2005, hereby submits its Reply Comments to the Public Utilties Commission of Nevada ("Commission") regarding processes, theories, and methodologies that may be used to establish just and reasonable rates in general rate cases pursuant to Section 7 of Senate Bil ("S.B") 238. INTRODUCTION The reply comments contained herein are intended to synthesize the Southern Nevada Water Authority's ("SNWA") general position with positions on rate making mechanisms presented by other paries on Januar 17, 2006. As made clear by the sum and substance of the comments to date, a single, clear, specific application of a test year methodology will be diffcult to attain. The SNW A nonetheless continues to support the general objective espoused by it, the utilties, and indirectly by other paries that the test year constrct should be intended to strke a balance between costs and revenues over the near term. The SNW A has offered its view on test year pariculars designed to balance costs and revenues in its previous two rounds of wrtten comments. While the comments reveal a clear division between the recommendations of the utilties and other paries on the value of the four alternatives designated by this Commssion, there appears to be consensus that a fully forecasted test year (Alternative 1) is the most costly and most contentious of the alternatives. It is most costly because it would represent a completely new forecast paradigm for estimating costs and the estimated test year costs would undoubtedly be higher than test year costs estimated under Alternatives 2-4. Having said this, the SNWA is also of the opinion that a completely 28 1111 C:\Documents and Settings\Dennis Peseau\Desktop\HLRNODOCS-#5 I 099 I -v l-SNW A_Reply_Comments _ Dkt_ 05-7048_ future _test"'ear.DO II Un..", 1 ..t'.c.1(.5'" J. V.L.. Draft SNWA 1/30106 Test Year Comments INTRODUCTION The reply comments contained herein are intended to synthesize the Southern Nevada Water Authority's general position on the issues and positions on rate making mechanisms presented by parties on January 17,2006. As made clear by the sum and substance of the comments to date, a single, clear specific application of a test year methodology wil be difficult to attain. The SNW A nonetheless continues to support the general objective espoused by it, the utilities and indirectly by other parties, thatthe test year construct should be intended to strike a balance between costs and revenues over the near term. The SNW A has offered its view on test year particulars designed to balance costs and revenues in its previous two rounds of wrtten comments. While the comments reveal a clear division between the recommendations of the utilties and other paries on the value of the 4 alternatives designated by this Commission, there appeared to be consensus that a fully forecast test year (Alternative I) is the most costly and most contentions of the alternatives. It is most costly because it would represent a completely new forecast paradigm for estimating costs and the estimated test year costs would undoubtedly be higher than test year costs estimated under Alternatives 2-4. Having said this, the SNWA is also of the opinion that a completely historic and unadjusted test year is also likely to be an inaccurate mechanism if near term significant cost events are occuring. ABIDING RATE MAKING PRICIPLES 6 7 8 9 ~10~o~oON,.I I~2o... t"~ :: 0\12; rt 00= ..n ~ o O~13(/ e ~... .. ;; ê rt 0 14o SZ O.;S ~ 15..-...o::Uo~ = ~.. 0 16o (/ ~ ;~U 17~ t"o t"~ t"18~ 19 20 21 22 23 I historic and unadjusted test year is also likely to be an inaccurate mechanism if near term significant 2 cost events are about to occur. 3 ABIDING RATE MAKING PRICIPLES 4 The SNW A proposes that this Commission consider the following principles in assessing 5 alternatives to test year mechanisms: · Both fully historic and fully future test year mechanisms are most inaccurate in times of rapid growth and growth events (such as major capital investment). · Modified, forward looking historical-based test years are most accurate in periods of rapid growt and growth events, so long as rate cases are fied timely and regularly, and updates are made for both costs and revenues. For these reasons, the SNWA strongly recommends that the Commission, utilities, and other paries work cooperatively and intentionally to devise a test year mechanism based upon historical data, but adjusted for near-tenn likely events beyond the rate case test year. The SNW A is ready, willng, and able to work with the Commission and other parties to define the appropriate adjustment period and the parameters for recognizing likely events. CONCLUSION The SNW A makes this recommendation largely because of the significant changes and challenges facing the Commission, utilities and rate payers in Nevada. As discussed in the SNWA supplemental comments, the electric utilities' recently anounced plans to expend $3 bilion for new generation and transmission facilities, over and above the Silverhawk, Lenzie and Tracy plants already underway, is likely to drastically alter the present cost strcture of those electric utilities. With unprecedented changes in costs, especially the changing ratio of fixed to variable costs, the SNW A 1/11 Peseau\Desktop\HLRNODOCS-# 51099 i -y I-SNW A_Reply_Comments _ Dkt_ 05-7048 Juture _test..ear,DOC Page z-ef 5 ---- - The SNW A proposes that this Commission consider the following principles in assessing alternatives to test year mechanisms: · Both fully historic and fully future test year mechanisms are most inaccurate in times of rapid growth and growth events (such as major capital investment) · Modified, forward looking historical-based test years are most accurate in periods of rapid growth and growth events, so long as rate cases are filed timely. For these reasons, the SNWA strongly recommends that the Commssion, utilities and other paries work cooperatively and intentionally to devise a test year mechanism based upon historical data, but adjusted for likely events 7-12 months beyond the rate case filing data. CONCLUDING REMARKS The SNW A makes this recommendation largely because of the significant changes and challenges facing the Commission, utilities and rate payers in Nevada. As discussed in the SNW A supplemental comments, the utilities recently anounced plans to expend $3 bilion for new generation and transmission facilities, over and above the Silverhawk, Lenzie and Tracy plants already underway wil drastically alter the utilities present cost structure. With unprecedented changes in costs, especially the changing ratio of fixed to variable costs, it is best to look at real and anticipated rather than forecast changes. i i In its prior comments the SNW A has stressed the need to focus on incremental generation, transmission and related costs in assessing the balance of costs and revenues. References to year experiences of the fewother jurisdictions attempting future test years is unlikely to be valuable under the circumstances facing growth in Nevada. 1 2 3 4 5 6 7 8 9 ."10~o~o ON .-11~2o... l' ." :: 0\12 ã en 00 i: ..~ t'o 0'"13I' 0 t'.§ i: ~en 0 o ~Z 14 O...~ 15~.- ...o;'üo~ i: ii.. 0 16o I' I' ã t' ~~ü 17~ l'o l' -; l'18~ 19 20 21 22 23 24 25 26 27 28 believes it is best to look at real and anticipated information in conjunction with actual experience, rather than rely solely on forecasted or estimated changes. i RESPECTFULL Y SUBMITTED this 30th day of January, 2006. BY: FRED SCHMIDT Hale Lane Peek Dennison and Howard 777 East Wiliam Street, Suite 200 Carson City, NV 89701 (775) 684-6000Attorney for SOUTHERN NEVADA WATER AUTHORITY i In its prior comments the SNW A has recognized and stressed the need to focus on incremental generation, transmission, and related costs in assessing the balance of costs and revenues. References to the experiences of the few other jurisdictions which employ future test year methodology is unlikely to be valuable to that focus under the unique circumstances facing growth in Nevada. It is also worrisome for customers to note that Nevada's neighbor, California, which has implemented a full future test year for ratemaking, according to the data submitted by Sierra PacificlNevada Power clearly has the highest electric utilty rates in the Western United States. As Nevada has learned from the Western Energy Crisis during the last decade, following California's lead in utilty regulation, while appealing in theory, can prove very costly. C:\Documents and Settings\Dennis Peseau\Desktop\HLRNODOCS-# 5 i 099 i -v I -SNW A_Reply_Comments _ Dkt_ 05-7048 Juture _test year, DOC Page 3 of..~ I 2 3 4 5 6 7 8 9 "0 10~o~o o C' ~11=.s 0... f'"0 ~ 0\12¡ rt 00 i: ~. el o 0 "0 13(f 0 el... ti ;: ã rt 0 14o ~ZO...~ 15.: _...o;,Uo~ i: ~ ~ 0 16o (f (f¡ el ~ ~~U 17 of''; f'18= 19 20 21 22 23 24 25 26 27 28 PROOF OF SERVICE I hereby certify that I mailed the foregoing Southern Nevada Water Authority's Supplemental Comments Regarding Rate Making Mechanisms in Docket 05-7048 by delivering via U.S.P.S. copies thereof, properly addressed for mailing to the following persons: Wiliam Staney Public Utilities Commission of Nevada 1150 E. Willam Street Carson City, NV 89701-3109 Alaina Burtenshaw Public Utilties Commission i 0 i Convention Center Dr., #250 Las Vegas, NV 89 i 09 Ernext Figueroa Bureau of Consumer Protection 555 E. Washington Ave., Suite 3900 Las Vegas, NY 89101 edfiguro~ag.state.nv. us Chad Duval Moss Adams LLP 3121 W. March Lane, Ste. 100 Stockton, CA 95219 chad.duvalcÐossadams.com Connie Silveira Sierra Pacific Power Company 6100 Neil Road Reno, NV 895 i i csilveira~sppc.com Dan Foley SBC Nevada Bell General Attorney P.O. Box 11010 645 E. Plumb Lane, Room B 132 Reno, NY 89520 Debra Jacobson Southwest Gas Corp. 5241 Spring Mountain Road Las Vegas, NV 89150 Debra.Jacobson~swgas.com Eric Heath Sprint of Nevada 330 S. Valley View Boulevard Las Vegas, NV 89 i 07 eric.s.heath~sprint.com Karen Peterson Allson, Mackenzie, et aL. P.O. Box 646 Carson City, NY 89702 kpeterson~allsonmackenzie.com Katheen Drakulich Kumer Kaempfer, et al. 5250 S. Virginia Street, Suite 220 Reno, NV 89520 kdrakulich~kkbr.com Linda Stinar Sprint of Nevada 330 S. Valley View Blvd. Las Vegas, NV 89107 Linda. c.stinar~mail.sprint.com Shawn Elicegui Lionel Sawyer & Collns i i 00 Ban of America Plaza 50 W. Liberty Street, Suite i 100 Reno, NV 89501 selicegui~lionelsawyer.com C:\Documents and Settings\Dennis Peseau\Desktop\HLRNODOCS-#5 I 099 i -v I-SNW A_ Reply-Comments _ Dkt_ 05-7048 Juture _test year, DOC " Dono 4- nÇ "J. 'lIS'"''!, -' , l "f . I 2 3 4 5 6 7 8 9 'i 10;0~oON~11:i.B 0... t"'i :: 0\12 ã CI 00= ..~ iu .~ ~~13 ....l ~ ã CI 0 14o §ZQ...~ 15,i ~...0:: Uo~ = i:.. 0 16o rI ~ ä ri U 17~ t"o t" i; t"18:i 19 20 21 22 23 24 25 26 27 28 Steve Lubertozzi Sky Ranch Water Service Corp. 2235 Sanders Rd. Northbrook, IL 60062 Timothy Shuba Goodwin Procter LLP 901 New York Ave. N.W. Washington, D.C. 20001 tshuba~goodwinprocter.com Dated this 30th day of Januar, 2006. \' Teresa A. Willams C:\Documents and Settings\Dennis Peseau\Desktop\HLRNODOCS-#5 I 099 i -v I -SNW A _Reply-Comments _ Dkt_ 05-7048 Juture _testyear,DO PageS of5. ....~".'"------- . _._~_...- ''\ Ed Evett Hale (1929.1993) Ste Lane J. Stli Peek Karen D. Dennin R. Cig Howan Step V. NO~'ik Richard L. Elmre Ridrd Dennett Robn C, Andn A1elt I. I'ngls lallL. Keny KeDy TCSlin N. Patrk Flanagan Matew Ii Woohtad Roiir W. Jepps Lalle C. Ea Jeremy J. Nork David A. Garcia FJis F. Cadish Timoth A. Lulu Fnirielc J. Schmidt James NewnTon R. So Patck J. Reily Seolt D. Fleming Sc SeIi Anthony L. Hall Frederi1c R. BaitJir Mallli B, Hipple Brad M. Johns Ji: M. Sn)'r Brent C. Eckerleyliri C. HalsMatd J. KreUl Brye K, KunimoinDola C. FIoJustin C, Jons Nicole M. Vance Kini Rohy Dora V. DjiliaßO'l Simon Jolm. Sarah E. L. ClsR. IC Mc lC.. Ilelm E. Mardroian OfCowil Roy Farrow Pauline Ng Lee Andrew Perl .AI ÎI He Vart.. 1'.. Jc..1).. A4Ï1ciiI ("..liRn Oty HALE LANE ATTORNEYS AT LAW m East Wiliam Str I Suite 200 I Carn City, Neva 8910t Telephone (775) 684- I Fac.imile (775) 684-(Ol ww.llebneco March 7, 2006 Crystal Jackson' Commssion Secretar 1150 E. Wiliam Street Carson City, NV 89701 RE: SNWA DIRCT TESTIMONY DOCKET NO. 06-01016 Dear Ms. Jackson: Please accept for filing the enclosed original and nine copies of the Direct Testimony of Dennis Peseau on behalf of SNW A in Docket No. 06-01016. Should you have any questions regarding this filing, please contact me at (775) 684-6000. :ii' nee ¡ely,~J. .Ijdmdf.,,'~ k. Fred Schmidt, Esq. FJS:taw Enclosures cc: Pares of Record HAtE LANE PEEK DENNISON AND HOWARD REO OFFICE: 5441 Kietze La I Send Floo I Ren. ~ewda 89511 I Phne (715)321.300 I Facsiniile (715) 786-6119 LAS VEGAS OFFICE: 2300 Wesi Saha Avenuc I Eighth Floor I Boii H I Las Vega. Neva 891021 Phone (702) 222.2500 i Facsimle (102) 365-6940 ::ODMA\POOLRJODOIS22386\\ o0':3S 1-! '''::.r.. -;..-.,'; .'.e. .~':"l - ."C..::::\-m,:=:o ,,.i;:.;r::.. tf cl:' . ;!"P-l'.~,~S .~:;.- .- (";;,; :-i'J~,.:¿i::N 1 2 3 4 5 6 7 8 9 10 11 Q. 12 A. 13 14 15 Q. 16 A. 17 18 19 Q. 20 A. 21 22 23 Q. 24 25 A. 26 27 Q. 28 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA Docket No. 06-01016 Direct Testimony of Dennis E. Peseau on behalf of Southern Nevada Water Authorit PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. My name is Dennis E. Peseau. My business address is 1500 Libert Street S.E., Suite 250, .Salem, Oregon 97302. BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED? I am President of Utilit Resources, Inc. The firm consults on a number of economic, financial, and engineering matters for various private and public entities. '~J.- ':'..o ~,,"ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? en .,~s:: r,n, :zu . ';.= i am testifing on behalf of the Southern Nevada Water Authority ("SNVYA"):äi1~ its .. ~:,:.constituent members. :-:.~~ ~ L-~:~-; ;/i;:.. .--, DOES ATTACHMENT 1 ACCURATELY DESCRIBE YOUR BACKGROUN AND EXPERIENCE? Yes. WHAT IS THE SUBJECT OF YOUR TESTIMONY? ::QOMA\PDOC\HLRNODOCS\52278\1 Page 1 I i A. 2 3 4 5 6 7 8 9 10 11 12 13 14 Q. 15 A. 16 17 18 19 20 21 22 23 24 25 Q. 26 A. 27 28 The subject of my testimony pertains to both the level and the design of Nevada Power Company's ("Company") proposed Base Tariff Energy Rate ("BTER") in these proceedings, Docket No. 06-10106. The Company's Application in these procedings seeks a combined residential and non-residential BTER designed to recover an annualized revenue increase of $264.1 milion, which includes both BTER and DEA synchronization. In its subsequent BTER update in this docket, filed February 24, . 2006, the Company reduced its request to $137.7 milion. The former requested increase of $264.1 milion is based on Nevada Power's use of a December 28, 2005 price forecast. The update to the BTER was based on a forecast made only a month later, January 27,2006. This large reduction in requested revenues demonstrates the significant impact and variation inherent in even near-term market energy price forecasts. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? The purpose of my testimony is twofold: 1. To demonstrate that implementation of a seasonal BTER. instead of an annual BTER, is at present necessary to relieve customers of excess carrying charges, to relieve Nevada Power of its chronic summer BTER revenue shortlls, and to reduce the excessive debt financing and credit rating stress promoted by an annualized BTER; and 2. To demonstrate that the continued decrease in forecast energy prices from the time of the Company's BTER update wil provide an easy transition to a seasonally-based BTER. WHAT CONCLUSIONS AND RECOMMENDATIONS DO YOU MAKE? My conclusions lead to the following recommendations: 1. A seasonally-based BTER that tracks Nevada Power's higher summer fuel and purchased power costs, and lower non-summer costs, should be implemented. ::ODMAIPCDOCS\HLRNOOOCS\522278\1 Page 2 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Q. 20 21 A. 22 23 24 25 26 27 28 2. A seasonally-based BTER would provide customers with prices that more accurately reflect their consumption decisions, and therefore promote better conservation decisions at times when costs are high. 3. A seasonally-based BTER, implemented in time for this summer season, would reduce or eÍiminate Nevada Power's need for an additional $200 millon in debt financing this Summer. 4. A seasonally-based BTER would permanently reduce a signifcant amount of debt necessary to finance the predictable summer BTER revenue shortalls. 5. The reduction in financing faciltated by a seasonally-based BTER would relieve customers of milions of dollars in additional carring charges. 6. The Commission should leave the annual average BTER reflected in current rates essentially unchanged for the next year, because fuel and purchased 'power prices have dropped dramatically since Nevada Powets February 24, 2006 update. However, by implementing a seasonally based summer BTER, the rate to be implemented commencing May 1, 2006 should be about $0.062/kwh, or about the same rate reflected in the February 24, 2006 updated filng by Nevada Power. PRESENT BTER STRUCTURE WHAT IS THE ISSUE WITH RESPECT TO THE PRESENT STRUCTURE OF THE BTER? The first issue i raise is the same whether the BTER is calculated using either a set of historical or forecasted data. As amended NAC 704.130 now provides, Nevada Power has offered both historical and forecasted prices. In either case, the BTER is estimated by averaging monthly price information into a single rate for each of the residential and non-residential categories. The averages reflect a compressionof high prices of fuel and purchased power faced and paid by Nevada Power in the summer, with the lower prices paid in shoulder and winter months. An average BTER is not designed to cover the Company's high ::OOMA\PCOOCS\HlRNODOCS\522278\1 Page 3 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Q. 20 21 A. 22 23 24 25 26 27 28 2. A seasonally-based BTER would provide customers with prices that more accurately reflect their consumption decisions, and therefore promote better conservation decisions at times when costs are high. 3. A seasonally-based BTER, implemented in time for this summer season, would reduce or eÍiminate Nevada Power's need for an additional $200 milion in debt financing this summer. 4. A seasonally-based BTER would permanently reduce a significant amount of debt necessary to finance the predictable summer BTER revenue shortalls. 5. The reduction in financing faciltated by a seasonally-based BTER would relieve customers of milions of dollars in additional carring charges. 6. The Commission should leave the annual average BTER reflected in current rates essentially unchanged for the next year, because fuel and purchased power prices have dropped dramatically since Nevada Power's February 24, 2006 update. However, by implementing a seasonally based suml1r BTER, the rate to be implemented commencing. May 1, 2006 should be about $0. 062/kh , or about the same rate reflected in the February 24, 2006 updated filng by Nevada Power. PRESENT BTER STRUCTURE WHAT IS THE ISSUE WITH RESPECT TO THE PRESENT STRUCTURE OF THE BTER? The first issue I raise is the same whether the BTER is calculated using either a set of historical or forecasted data. As amended NAC 704.130 now provides, Nevada Power has offered both historical and forecasted prices. In either case, the BTER is estimated by averaging monthly price information into a single rate for each of the residential and non-residential categones. The averages reflect a compression of high pnces of fuel and purchased power faced and paid by Nevada Power in the summer, with the lower prices paid in shoulder and winter months. An average BTER is not designed to cover the Company's high ::ODMA\PCDOCS\HLRNODOCS\522278\1 Page 3 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Q. 20 21 A. 22 23 24 25 26 27 28 2. A seasonally-based BTER would provide customers with pnces that more accurately reflect their consumption decisions, and therefore promote better conservation decisions at times when costs are high. 3. A seasonally-based BTER, implemented in time for this summer season, would reduce or èÍiminate Nevada Power's need for an additional $200 milion in debt financing this Summer. 4. A seasonally-based BTER would permanently reduce a significant amount of debt necessary to finance the predictable summer BTER revenue shortalls. 5. The reduction in financing faciltated by a seasonally-based BTER would relieve customers of milions of dollars in additional carrying charges. 6. The Commission should leave the annual average BTER reflected in current rates essentially unchanged for the next year, because fuel and purchased power prices have dropped dramatically since Nevada Power's February 24, 2006 update. However, by implementing a seasonally based summer BTER, the rate to be implemented commencing May 1 r 2006 should be about $0.062Ikh, or about the same rate reflected in the February 24, 2006 updated filng by Nevada Power. PRESENT BTER STRUCTURE WHAT IS THE ISSUE WITH RESPECT TO THE PRESENT STRUCTURE OF THE BTER? The first issue I raise is the same whether the BTER is calculated using either a set of historical or forecasted data. As amended NAC 704.130 now provides, Nevada Power has offered both historical and forecasted prices. In either case, the BTER is estimated by averaging monthly pnce information into a single rate for each of the residential and non-residential categones. The averages reflect a compression of high prices of fuel and purchased power faced and paid by Nevada Power in the summer, with the lower prices paid in shoulder and winter months. An average BTER is not designed to cover the Company's high ::ODMA\PCDOCS\HLRNODOCS\522278\1 Page 3 1 2 3 4 5 6 7 8 9 10 Q. 11 12 A. 13 14 15 16 17 18 Q. 19 A. 20 21 22 23 24 25 26 27 28 summer costs, and requires at least short-term financing to pay for such costs. Nevada Power explains in several places in its Application and testimony In this case. and in its Docket No. 06-01018 Application, that even if it requested BTER is granted in its entirety. it expects to experience accrued deferrals of up to $200 millon. The specifc Issue I am raising is the inabilty of the BTER, if estimated and set at an average level over the entire test year, to track the out-of-pocket costs for fuel and purchased power incurred by the Company. SEASONAL BTER WHAT DO YOU PROPOSE TO REPLACE THE CURRENT METHOD OF ESTIMATING AND SETTING THE BTER ON AN AVERAGE ANNUAL BASIS? I propose that the monthly calculations that are currently developed for the BTER not be reduced to a single annual figure, but instead be set and charged on a seasonal basis. The summer BTER would be based on the forecast prices for the months June through September, while the non-summer BTER would be based on the forecast prices for the months of October through May. WHY DO YOU MAKE THIS PROPOSAL? First and foremost, as an economist who has worked before this Commission for many years, I recognize that whenever possible and practical rates to customers have been based on costs, particularly marginal costs. A seasonally-based BTER would promote an alignment of rates with the pronounced seasonality of fuel and purchased power costs. Under the existing annual BTER, customers have little or no knowledge of the ' prevalence of high summer fuel and purchased power costs as compared to non- summer months, nor do they have the ability to shape or avoid consumption that can reduce their power bils. All customers now pay too little for power consumed in ::ODMA\PCDOCS\HLRNODOCS\22278\1 Page 4 1 2 3 4 5 6 7 8 9 10 Q. 11 12 A. 13 14 15 16 17 18 Q. 19 A. 20 21 22 23 24 25 26 27 28 summer costs, and requires at least short-term financing to pay for such costs. Nevada Power explains in several Rlaces in its Application and testimony in this case, and in its Docket No. 06-01018 Application, that even if its requested BTER is granted in its entirety, it expects to experience accrued deferrals of up to $200 milion. The specifc issue i am raising is the inabilit of the BTER, if estimated and set at an average level over the entire test year, to track the out..of-pocket costs for fuel and purchased power incurred by the Compcmy. SEASONAL BTER WHAT DO YOU PROPOSE TO REPLACE THE CURRENT METHOD OF ESTfMATING AND SEmNG THE BTER ON AN AVERAGE ANNUAL BASIS? i propose that the monthly calculations that are currently developed for the BTER not be reduce to a single annual figure, but instead be set and charged on a seasonal basis. The summer BTER would be based on the forecast prices for the months June through September, while the non-summer BTER would be based on the forecast prices for the months of October through May. WHY DO YOU MAKE THIS PROPOSAL? First and foremost, as an economist who has worked before this Commission for many years, I recognize that whenever possible and practical rates to customers have been based on costs, particularly marginal costs. A seasonally-based BTER would promote an alignment of rates with the pronounced seasonality of fuel and purchased power costs. Under the existing annual BTER, customers have little or no knowledge of the prevalence of high summer fuel and purchased power costs as compared to non- summer months, nor do they have the ability to shape or avoid consumption that can reduce their power bils. All customers now pay too little for power consumed in ::ODMA\PCDOCS\HlRNODOS\522278\1 Page 4 1 2 3 4 Q. 5 6 A. 7 8 9 10 11 12 13 14 15 16 17 18 Q. 19 20 A. 21 22 23 24 25 26 27 28 summer months and too much for power consumed the rest of the year. A seasonally- based BTER promotes effcient usage decisions, as well as economic conservation. WHAT OTHER BENEFITS DERIVE FROM THE REDESIGN OF THE ANNUAL BTER TO A SEASONALL V-BASED BTER? The corollary to thè annual BTER-induced customer uflderpayment of the high summer months' fuel and purchased power costs is the shortall of revenues collected by Nevada Power in the summer months. The Company speaks to this revenue shortall throughout its filing (Application, p. 4, lines 18-20; p. 17, i. 25-27; Yackira Direct, p. 1~, i. 11-21; and in its Application in Docket 06-01018. p. 12, i. 5-18). Depending on a number of factors, Nevada Power indicates the need for up to $200 millon in additional financing to cover accumulated and prospective BTER revenue shortalls. Seasonalizing the BTER to track seasonal fuel and purchased power costs should eliminate the need for this financing by providing substantial additional revenue and cash flow to pay for higher fuel and purchased power costs during summer months. WOULD THE SEASONALLY-BASED BTER POSITIVELY AFFECT NEVADA POWER'S FINANCIAL FUNDAMENTALS? Yes. As I indicated, the seasonally-based BTER improves the Company's cash flow and rerjuces the need for substantial new debt. As many have noted in recent years, Nevada Power and its parent, Sierra Pacific Resoúrces, have been excessively debt leveraged for some time. In my opinion, any and all positive steps toward reducing the Company's need for debt would have favorable consequences for Nevada Power's customers, shareholderS, and bondholders: Credit rating agencies such as Moody's and Standard & Poor's have implored the Company to improve the important debt- equity ratio. The net effect of a more balanced capital structure is a lower cost of capital through lower debt costs. ::ODMA\PCDOCSlHlRNODOCI522278\1./Page 5 2 Q. 3 4 A. S 6 7 8 9 10 11 12 13 14 15 Q. 16 17 A. 18 19 20 21 22 Q. 23 A. 24 25 26 27 28 . WHAT OTHER BENEFITS WOULD ACCOMPANY THE IMPLEMENTATION OF A SEASONALLY -BASED BTER? As noted in the testimony of Company witness Mr. Yackira. p. 10, 1.16-17, substantial carrying charges of $23.4 millon are included in DEA5 balances. In addition, Period 6 deferred balance could reach $178 milion under an annualized average BTER. A seasonally-based BTER designed to avert the summer months under recovery would minimize deferred balances and save customers the 9.03 percent carrying charge rate which is applied to these balances. If the entire $200 milion in new debt requested in Docket 06-01018 is avoided, the seasonally-bas€d BTER could minimize or eliminate annualized carrying charges of up to $18 milion. CALCULATING A SEASONALLY-BASED BTER HAVE YOU CALCULATED A SEASONALLY-BASED BTER BASED ON NEVADA POWER'S FEBRUARY 24, 2006 FILING? Yes. My Exhibit DEP-1 summarizes Nevada Power's February 24, 2006 updated price forecasts and associated annual BTER. This exhibit then seasonally diferentiates the Company's revised annual BTER of $0.063253 into seasonal components. PLEASE EXPLAIN. Exhibit DEP-1 distinguishes by month. by season, and by test year the fuel and purchased costs forecast by the Company. For example, dividing the total test year sales of 20,243,888 mwhs into the net retail cost (after removing the FERC allocation) of $1,277,325,000, we obtain Nevada Power's requested annual BTER of $0.06325/kh, before adjustment for Hoover B. To seasonalize this annual BTER, the ::ODMA\PCDOCS\HLRNODOCS\522278\1 Page 6 1 2 3 4 5 6 7 8 9 Q. 10 11 12 A. 13 14 Q. 15 A. 16 17 18 19 20 21 22 23 24 Q. 25 26 27 28 forecast of summer and winter fuel and purchased power costs is divided by the related forecast energy sales. The Hoover B adjustment of approximately $7,177,000 in favor of the residential class result in a net reduction of $.00083 for residential, and a net addition of $.00062 for non-residential. The final seasonal BTERs based on Nevada Powets February 24, 2006 update are shown at the bottom of Exhibit DEP-1, $0.06242 for residential and $0.06387 for non-residentiaL. ARE YOU RECOMMENDING THAT NEVADA POWER'S PROPOSED ANNUAL BTER LEVEL BE ADOPTED AND THEN SEASONALIZED IN THESE PROCEEDINGS? No. WHY NOT? After i noticed the significant decrease in Nevada Power's proposed BTER from its January 17, 2006 filing forecast to its February 24, 2006 revised forecast, i further updated the fuel and purchased power forecast to March 1, 2006. The seasonally- based BTER I develop below and recommend in these proceedings is calculated with this later, more current forecast. After i noted that Nevada Power's original January 17, 2006 BTER filing prOposed to collect $264.1 milion in revenues, the Company's update of February 24, 2006 reduced its request to $137.7 million, a reduction of over $126 milion. BEFORE YOU EXPLAIN YOUR REVISED SEASONALLY-BASED BTER CALCULATIONS BASED ON YOUR MARCH 1 FORECAST, PLEASE ÉXPLAIN HOW YOUR PRICE FORECASTS AND RELATED SEASONALLY-BASED BTER COMPARE TO THE FORECASTS AND BTER PROPOSED BY NEVADA POWER ON FEBRUARY 24, 2006. ::ODMA\PCDOCS'lLRNODOCS\52227B\1 Page 7 A. 2 3 4 5 6 7 8 9 10 11 12 13 Q. 14 15 16 A. 17 18 19 20 21 22 23 24 25 26 27 Pnces for both fuel and purchased power for the test year are now forecasted to be lower than the forecasts used ay Nevada Power. This, of course, results in a lower estimated annual BTER forecast. But, due to the seasonally higher summer BTER rates I calculate below, use of the seasonal BTER will pose no greater risk of revenue under-recovery than the BTER propoed by the Company on February 24, 2006. This is due essentially to the fact that my proposed summer BTER is estimate to be very nearly the same as the updated BTER proposed by Nevada Power. The diference is that the non-summer rate i estimate is approximately $8/mwh lower, but this lower rate should not go into effect unti October of this year, when fuel and purchased power costs normally decrease, barrng no significant changes in fuel and purchased power markets by that time. PLEASE EXPLAIN YOUR UPDATE OF FUEL AND PURCHASED POWER MARKETS AND THE DERIVATION OFSEASONALlY.BASED BTER BASED UPON THAT FORECAST. My update, and recommended seasonally-based BTER, is shown on my Exhibit DEP- 2. All significant data and assumptions used by Nevada Power were also used in my revised analysis, with the notable exception of its fuel and purchased power forecast. Upon review of the forward market natural gas and electric prices, i found that prices had continued the downward trend found by Nevada POVler by the end of January. In fact, the March 1, 2006 natural gas price markets had fallen slightly over 10 percent from the forecast used by Nevada Power.1 The fuel and purchased power costs for the summer and winter periods shown on Exhibit DEP-2 reflec this decrease in costs. These fuel and purchased power prices adjusted to March 1, 2006 are then developed into seasonally-based BTERs on Exhibit DEP-2, in the same fashion as those in Exhibit DEP-1. 28 1 For example, this was derived from observing a decrease in natural gas NYMEX price of $1.37/mmbtu from Nevada Power's prices. Purchased power pnces were also lower since they are heavily influenced by natural gas costs. ::ODMA\PCOOCS\HLRNOOOS\52228\1 Page 8 1 2 3 4 5 6 7 8 9 10 11 Q. 12 13 A. 14 15 16 17 18 19 Q. 20 A. 21 22 23 24 Q. 25 A. 26 27 28 The final result of these adjustments result in my proposed seasonally-based BTERs in these proceings. Proposed BTERs Summer Winter Residential $0.06125 $0.06270 $0.05318 $0.05463Non-Residential The summer BTER is generally applicable to months June through September, while the non-summer BTER is applicable for months October through May. ARE YOU AWARE OF THE FACT THAT NEVADA POWER IS REQUESTING THAT THE BTER BE IMPLEMENTED BEGINNING MAY 1, 2006? Yes, and this could cause a bit of discontiauity in terms of rate design, as the lower non-summer rate is really most appropriate for May 1, 2006. However, the Commission may not wish to implement the lower rate for one month, followed by the higher summer BTER, especially since May is a shoulder month with consumption and costs. nearly approaching summer month levels. DO YOU HAVE A RECOMMENDATION IN THIS REGARD? Yes. i recommend that the higher summer BTER be implemented on May 1, 2006 as. a special circumstance related to the Company's request for early summer implementation. WHY DO YOU MAKE THIS RECOMMENDATION? i make this recommendation for several reasons. First, implementation in May provides some rate continuity. Second, the Company indicates that it wil be carring positive deferral balances into this new test year, thus there is no reason to lower current BTER rates for one month. Lastly, it wil provide some cushion for summer ::ODMA\PCDOCLRNOOOS\52278\1 Page 9 1 2 3 4 Q. 5 A. 6 7 8 9 10 11 12 13 14 15 16 17 Q. 18 A. 19 20 21 22 23 24 25 26 27 Q. 28 A. costs, although my updated forecast indicates that the Company-predicted summer revenue shortall should be largely, if not entirely, eliminated, as well be the need for, its referenced $200 millon additional debt financing. DO YOU HAVE A PROPOSAL FOR IMPLEMENTING THE NON-8UMMER BTER? Yes. If the most recent forecast is accurate, the approximately 8 mil/kwh reduction in the BTER would commence October 1, 2006. However, as a transitional accommodation, i recommend that Nevada Power be allowed to update the natural gas and electric forecasts by the end of August if there is signifcant change from the March 1, 2006 forecasted prices. This accmmodation is simply to eliminate the risk of market change against it at that time, and to allay any angst from the financial institutions that the transition to seasonal rates could be negative to the Company. Since a higher BTER wil already be in place, the abilty to accommodate a change in forecasted prices would also be easy to implement if it just meant not lowering the non-summer BTER as much as estimated for October 1, 2006. SUMMARY AND CONCLUSIONS PLEASE SUMMARIZE YOUR CONCLUSIONS. I recommend that: 1. The seasonal rates summarized in my Exhibit DEP-2 be implemented in this case. 2. The higher summer BTER rate, ordinarily put in place for the first summer month of June, be implemented as a one-time exception this May 1, 2006. 3. Nevada Power be allowed to re-file a fuel and purchase power update in August that might, or might not, afect the degree to which the non- summer rates to be implemented October 1, 2006 are reduced. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? Yes. ::ODMA\PCDOCSlRNODOCS\52278\1 . . Page 10 AFFIRMATION I, Dennis E. Peseau, pursuant to NAC 703.710 hereby affirm that the foregoing prepared testimony was prepared by me or under my direction and is correct to the best of my knowledge. Signed Dated 12,~- ~- t:'1 t)' ATTACHMENT 1 Attachment 1 Dkt. 06-01016 Witness: D.E. Peseau Page 1 of3 STATEMENT OF OCCUPATIONAL AND EDUCATIONAL HISTORY AND QUALIFICATIONS DENNIS E. PESEAU Dr. Peseau has conducted economic and financial studies for regulated industries for the past twenty-eight years. In 1972, he was employed by Southern California Edison Company as Associate Economic Analyst, and later as Economic Analyst. His responsibilties included review of financial testimony, incremental cost studies, rate design, econometric estimation of demand elasticities and various areas in the field of energy and economic growth. Also, he was asked by Edison Electrical Institute to study and evaluate several prominent energy models as part of the Ad Hoc Committee on Economic Growth and Energy Pricing. From 1974 to 1978, Dr. Peseau was employed ,by the Public Utilty Commissioner of Oregon as Senior Economist. There he conducted a number of economic and financial studies and prepared testimony pertaining to public utilties. In 1978 Dr. Peseau established the Northwest offce of Zinder Companies, Inc. He has since submitted testimony on economic and financial matters before state regulatory commissions in Alaska, California, Idaho, Maryland, Minnesota, Montana, Nevada, Washington, Wyoming, the District of Columbia, the Bonnevile Power Administration and the Public Utilties Board of Alberta on over one hundred occasions. He has conducted marginal cost and rate design studies and Ii i I Attachment 1 Dkt. 06-01016 VVUness: D.E. Peseau Page 2 of3 prepared testimony on these matters in Alaska, California, Idaho, Maryland, Minnesota, Nevada, Oregon, Washington and in the District of Columbia. He has also conducted cost and rate studies regarding PURPA issues in the states of Alaska, California, Idaho, Montana, Nevada, New York, Washington, and Washington, D.C. Dr. Peseau holds B.A., M.A. and Ph.D. degrees in economics. He has co-authored a book in the field of industrial organization entitled, Size, Profits and Executive Compensation in the Large Corporation, which devotes a chapter to regulated industries. Dr. Peseau has published articles in the following professional journals: Review of Economics and Statistics, Atlantic Economic Journal, Journal of Financial Management, and Journal of Regional Science. His articles have been read before the Econometric Society, the Western Economic Association, the Financial Management Association, the Regional Science Association and universities in the United Kingdom as well as in the United States, He has guest lectured on marginal costing methods in seminars in New Jersey and California for the Center of Professional Advancement. He has also guest lectured on cost of capital for the public utility industry before the Pacific Coast Gas and Electric Association, and for the Executive Seminar at the Colgate Darden Graduate School of Business, University of Virginia. Attachment 1 Dkt. 06-01016 Witness: D.E. Peseau Page 3 of3 Dr. Peseau and his firm have participated with and been members of the American Economic Association, the American Financial Association, the Western Economic Association, the Atlantic Economic Association and the Financial Management Association. He was formerly a member of the Staff Subcommittee on Economics of the National Association of Regulatory Utilty Commissioners. Dr. Peseau has been President of Utilty Resources, Inc. since 1985. I i I '. Month Nevada Pow Company Calculation of Seasonallz Bas Tariff Energy Rates AnnuaUze for Uie Twelve Months Ended Novmber 30, 2005 Foreat fo the Tweve Mo Ended April 30, 2007 (000$1 Exhibit DEP-1 Page 1 of1 Peseau Fuel and Purcse Powr Cost Forecasted Mw Ene SalesNevadaSummerWinterTotalSurnl!Nevada Wintl!FERC Totl98,574 1.711.457 4.59130.203 1.987.807 9,283169.496 2.497.571 13,940158.747 2.251,98 13.868124.419 1.748.82790.426 1.288.9674.349 1.487.914 81784.310 1.523.952 1,2099.033 1.53.124 2.51468.34 1.30,185 1.17085.695 1.44,839 24476.796 1.39,025 582,865 697,528 1.26,393 8.86.193 11.709.892 47.803 20.243.888 2.381 687 3.068 58.48 696.841 1.277.325 $0.06840 $0.05951 $0,06325 May-0June July-06 August-oSepte-0 Ocber.Q6Novber-0 Decmbe.Q Januaiy-07 Febriy.Q7 Mard-07 Apri7 Total Less FERC Alloction Nel Retail Co Cot per kWh befor Hoove Adjustments for Hoover B Hover B Benefit Allocn of Hoo B to Non- Residential Alloction of Hoovl! B Befit to Residential Residential Sales Non-Residential Sals Total Sales Net Ho B Ben to Resideal pe kWh Net Hoor B Cot to Non- Residential per kWh Cost per kWh Afer Hoover Re&ienlial Non-Residential 12.545 7.177 (7.177) 6.641.455 11.55.629 20.196.08 ($0.0083) $0,002 Summ Winter Total $0.06757 $0,06902 $0.05868 $0,06013 $0.06242 $0.06387 Sourc: Exhibit E(Rev) and Exhibit E-1 (Re) Page 16 .. . .. Month May-oJun July-o August-oSepter-060c-0 NOveer-06Dec-o January-07 Febrry-07 Marc-07 Aprii-07 Total Less FERC Allocn Net Retail Co Cost per kWh before Hoo Adjustmnt for Hooer B Hoover B Benet AUoction of Hoover B to Non-Resideti AUoctin of Hover B Benefit to Residential Resdential Sas Non-Resktial Sales TolalSales Net Hoover B Benefi to Residential pe kWh Net Hoove B Cost to Non. Residential per kWh Cost pe kWh Afr Hooer Residential Non.Residetial Exibi DEP-2 Page 1 of 1 Peseau Neva Powr Company Calculaton of SeasonaUz Base Tariff Energ Rates Annualiz for the Twelv Month End November 30, 2005 URI Adjusted Forst for the Twe Mon Ended April 30, 2007 (00$) Fue and Purcase Power Cot Foreste Mw Ene Sale NevadaSummerWinterTotlSumme Nevada Winte FERC Tolal89,46 1,711,457 4.759118,168 1,987,807 9,28153,829 2,497,571 13,94144.074 2,251,988 13,86112,919 1,748,82782,068 1,288,39667,477 1,467,914 81776,517 1,523,952 1,20889,879 1,538,124 2,51480;179 1,300,185 1,17077,774 1,440,839 24469,698 1,43.025 528.991 633,055 1,162,04 8,48,193 11,709,892 47,80 20,243,888 2,160 624 2,784 526,830 63,431 1.159,262 $0,06208 $0,051 $0.05740 12,545 7,177 (7,177) 8.641,45 11.55,629 20,196,084 ($0,00083) $0,00062 Summr Winter Tolal $0.06125 $0,06270 $0,05318$0.05 $0.0567 $0,0582 Source: Exhibit E(Rev) and exibit E-1(Rev) Page 17 ! . 1 2 PROOF OF SERVICE 3 ' I hereby certif that I have this day served a copy of the foregoing Direct Testimony of 4 Dennis E. Peseau on behalf of Southern Nevada Water Authority in Docket 06-0101~upon 5 each of the parties listed below by hand delivery or by electronic mail and U.S. Mail, properly 6 addressed, with postage prepaid to: 23 24 25 11/ 26 11/ 27 11/ 28 /111 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 Elizabeth Ellot Associate General Counsel Nevada Power Company 6100 Neil Road Reno, NV 89520 Fax: 775-834-4098 Email: bellot(§sppc.com Julia E. Sullvan Law Offce of Julia E. Sullvan, LLC 219 A Duke of Gloucester Stret Annapolis, MD 21491 Fax: 410-990-9461 Email: juliasullvanCëjeslaw.us Staff Counsel Public Utilities Commission 1150 E. Wiliam Street . Carson City, NV 89701 Email: aburtens(cpuc.state.nv.us Richard Hinckley, Esq. Public Utilties Commission 1150 E. Wiliam Street Carson City, NV 89701 Fax: 775-834-4098 Email: hincklevtpuc.state.nv.us Dale Swan Exeter Associates, Inc. 5565 Sterrett Place, Ste. 310 Columbia, MO 21044-2690 Fax: 410-992-3445 Email: dswan4ìexéterassociates.com ::ODMA\PDOCS\HLRNODOCS\22746\1 Mark Russell, Esq. Mirage Hotel and Casino 3400 Las Vegas Blvd. South Las Vegas, NV 89109 Fax: 702-792-7628 Email: mrusseiiøimirage.com Jon Wellnghoff, Esq. Beckley Singleton Chtd. 530 Las Vegas Blvd. South Las Vegas, NV 89101 Fax: 702-385-9447 Email: jwellnghoff(§beckleylaw.com Charles K. Hauser, Esq. Southern Nevada Water Authority 1001 S. Valley View Blvd. Las Vegas, NV 89153 Fax: 702-258-3268 Eric Witkoski, Esq. Consumer Advocate Bureau of Consumer Protection 555 E. Washington Street, Suite 3900 Las Vegas, NV 89101 Email: epwitkostmag.state.nv.us Phil Wiliamson, Financial Analyst Bureau of Consumer Protection 100 N. Carson Street, Suite 200 ' Carson City, NV 89701 Fax: n5-687 -6304 Email: pjwillaCtag.state.nv.us Page 18 Lawrence A. Gollomp Assistant General Counsel 2 U.S. Department of Energy 1000 Independence Avenue, SW 3 Washington, D.C. 20585 Fax: 202-586-7479 4 Email: Lawrencè.Gollomp(hq.doe.gov 5 Dated this ~ay of March, 2006. 6 ¿Z2~)7 An employee of Hale Lane Peek 8 Dennison and Howard 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 :;ODMA\PCDOCS\HLRNODOCS\s22746\1 Page 19 " Conley E. Ward (ISB No. 1683) GIVENS PURSLEY LLP 601 W. Banock Street P.O. Box 2720 Boise, ID 83701-2720 Telephone No. (208) 388-1200 Fax No. (208) 388-1300 cew~givenspurley .com RECEIVED. inFiLED 0 llfll ~lUN 21 PH 3: 34 IDA,HO PUElIC UnUTiES COMNlSSlON .7/7/1141 l' E~C l IitJ ç.J Attorneys for Potlatch Corporation. S:IC1ESlJ3I4\S4\P Dire Tcsimon,DQ BEFORE TH IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION OF AVISTA CORPORATION FOR THE AUTORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC AND NATUL GAS SERVICE TO ELECTRC AND NATURA GAS CUSTOMERS IN TH STATE OF IDAHO. Case Nos. AVU-E-04-1 AVU-G-041 DIRECT TESTIMONY OF DENNIS E. PESEAU ON BEHALF OF POTLATCH CORPORATION June 21, 2004 .OR1GtNAL 1 Q.PLEASE STATE YOUR NAM AN BUSINSS ADDRESS. 2 A.My nae is Dennis E. Peseau. My business address is Suite 250, 1500 Libert Street, 3 S.E., Salem. Oregon 97302. 4 Q.BY WHOM AND IN WHT CAPACITY AR YOU EMPLOYED? 5 A.I am the President of Utility Resources. Inc. ("UR"). UR has consted on a number of 6 economic, financial and engineerig mattrs for varous private and public entities for 7 more than twenty years. 8 Q.PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND WORK 9 EXPERINCE. 10 A.My resume is attached as Exhibit No. 201. 11 Q.HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE IDAHO PUBLIC UTILITIES 12 COMMISSION? 13 A.Yes, on many occasions. 14 Q.FOR WHOM ARE YOU APPEARG IN THIS CASE? 15 A.I am appearng on behaf of Potlatch Corporation ("Potlatch"). 16 Q.WHT IS TH PUROSE OF YOUR DIRECT TESTIMONY? 17 A.I have been asked to review Avista's applications in ths case and make appropriate 18 recommendations to the Commssion. 19 Q.PLEASE PROVIDE A SUMMRY OF YOUR TESTIMONY. 20 A.My testimony deals with four major issues, all concerning the application for an increase 21 in electric rates. Afer reviewi the evidence, I conclude that: DIRECT TESTIMONY OF DENNIS E. PESEAU - 2 IPUC Case Nos. A VU-E-041 and A VU-G-041 ...................1 .. ........~... 1 1.The Coyote Springs 2 generating plant should be excluded from rate base on 2 severa grounds, not the least of which is that the plant is not "used and usefu" in 3 providing service to Avista's ratepayers. 4 2.A vista should not be allowed to recover the cost of natural gas hedges or swaps 5 put on in April and May of 200 1 because they were imprudent and intended to benefit 6 Avist's unegulated activities at the ratepayers' expense. 7 3.Avista's use of a 2002 test year, adjusted for allegedly known and measurble 8 chages, produces a mismatch of expenses and rate base, on the one hand, and revenues 9 on the other. I offer 3 alternative methods of correctig ths mismatch. 10 4.Avist's inclusion of Potlatch's Lewiston Facilty in Schedule 25 for rate design 11 purses is unreasonable on its face, and Avista's cost of service study overstates the 12 anua cost of servng Potlatch by approximately $1.4 milion per year. 13 In addition, John Thornton will present Potlatch's cost of capita testimony and its 14 recommendation for a retur on equity for A vista. However, in the recently completed 15 Idaho Power rate case, I offered a critique of Dr. Avera's testimony that showed that 16 updated data and a consistent application of his methodology demonstrate that his cost of 17 equity is overstated, even if one accepts his assumptions. I fear that if I were to not 18 perform a similar analysis in this case, the Commission would draw the unwaranted 19 inference that my critique is no 10nger valid. To forestl ths inference, I have prepared 20 and atthed an Appendix to this testimony that once again shows that simple updates to 21 Dr. Avera's data and the use ofinternally consistent data employed within his retu on 22 equity methods, dramatically lower his ret on equity estimate below the 10.4% to 23 1 i .9% equity cost range (afer the addition of flotation costs) he estimates for benchmark DIRECT TESTIMONY OF DENNIS E. PESEAU - 3 IPUC Case Nos. A VU-E-04-1 and A VU-G4-1 ...................t.... 1 electric utilities in the western U. S.. and below the 11.5% equity retu he endorses for 2 Avista. 3 Coyote Springs 2 4 Q.WOULD YOU PLEASE EXPLAIN TH ISSUES CONCERNING TH COYOTE 5 SPRIGS 2 GENERATIG PLANT? 6 A.Before I do so, a short preface is in order. The two topics I next discuss in ths testiony 7 raise very distubing issues about the relationship between Avista's regulated and 8 ungulated ar. In order to underand the significace of these issues. the 9 Commission needs to have a clear understading of A vista's peculiar corporate stctue. 10 Consequently, I have reproduced below Scott Morrs' Avista organzational cha from 11 his Exhbit No.1. page 5 of 5: DIRCl TESTIMONY OF DENNIS E. PESEAU - 4 IPUC Case Nos. A VU-E-4-1 and A VU-G1 ...................f ......."...,... 1 2 Q. 3 4 A. 5 6 7 8 9 10 11 Avista Corporation Company Overview ô -I AVÍ Ei I o .clleab..,entiy o . de.. au opdii diviri or lin ofbu EihlllNo.1S.MoI.Avtsl Corpallon PLEASE DESCRIE TH ENTIS AN OPERATING DIVISIONS ON THE CHART. Avista's wieguated enterrises appear on the right hand side of the char. Avist Capita is a holding company for these enterprises. A vist Advantage provides inormtion services and related business servces. Neither it nor the operating division labeled "Other" figue in my testimony. The two entities engaged in "Energy Marketig and Resource Management," on the other hand, playa prominent role in the followig discussion. Avista Power is Avista Corpration's il-fated entr into the merchat power business. It was originally designed to build or acquir generatig plants and other DIRCT TESTIMONY OF DENNIS E. PESEAU - 5 IPUC Case Nos. AVU-E-4-1 and AVU-G041 ...................f .............,.... 1 2 3 4 5 6 7 8 9 10 Q. 11 12 A. 13 14 is 16 17 18 19 Q. 20 A. 21 22 23 resources to serve the uneguated wholesale electrcity markets. According to Avista's testimony it is now inctive, but it was the original owner of the Coyote Sprigs 2 generating plant and it stil own 49% of the Rathdr merchant plant. Avista Energy is Avista Corporation's energy trading ar. Its pr purose is to trade in both the electrcity and natual gas markets. In addition, it brokers deas for Avita Utilities, although the Washington Utilties and Trasporttion Commssion recently ordered the termination of ths relationsp with respect to natural gas purhaes. At the peak of its activity it generated revenues far in excess of A vista Corporation's regulated public utility sales. YOU EARIER DESCRIED AVISTA CORPORATION'S ORGANIZATIONAL CHAT AS "PECULIAR." WHT DID YOU MEAN? The right hand side of the char is not at all unusual for a utilty. Most utilities place uneguated activities in separate entities. The left hand side is quite the opposite. All of the utilities I am familar with organize the utility fuction as a separte business entity, which makes its own purchases and business deas separte and apar from the unegulated enterprises. But in Avista's case, there is no separate utility entity, only an operating division. In effect, "A vista Utilities" is simply a name for the residua holder of A vista Corporation assets that are not claimed by one of the unegulated entities. WHAT DIFFERENCE DOES AVISTA'S ORGANIZATION MA? It blurs the distction between regulated and uneguated activities. In the last A vista rate case, I complaied, apparently not stenuously enough, that Avista's corporate strtue, and its practce of not contemporaneously marking trades to its regulated or non-regulated ar, left it with the latitude to subsequently alocate tres based on their DIRCT TESTIMONY OF DENNIS E. PESEAU - 6 IPUC Case Nos. AVU-E-041 and AVU-G-1 ............ ....., ..........-..\.... 1 2 3 4 Q. 5 A. 6 7 8 9 10 ii 12 Q. 13 A. 14 15 16 17 18 Q. 19 20 A. 21 22 Q. profitabilty. I characterized ths situation as analogous to a stockbroker who makes investents and then, months or even years later, decides whether the purchases were for his own or his customer's account. is THIS STILL A PROBLEM? In fact, the present case is far worse. In the case of Coyote Sprigs 2 ("CS2"), the uneguated entity (Avista Power) purchased a plant that subsequently proved to be a disaster. What is the Company's afer the fact position? "We (Avista Corpration) ordered that traction by our unegulated subsidiar (A vist Power) for the 'benefit' of our regulated customers." Ths is analogous to a broker buying a stock for his own account, and then two years later, when the trade is hopelessly under water, declarng tht the trade was really for the cusomer's account. HOW DID CS2 GET STARTED? The CS2 fiasco began, like many other recent energy debacles in the West, with Enron playing i: prominent role. CS2 was onginaly a Portland General Elecc ("PGE") project to be built as a companion to PGE's Coyote Spnngs 1 generating station located near Boardman, Oregon. PGE was a regulated Enron subsidiar dunng the entirety of the CS2 saga. DID ENRON PLAY ANY ROLE IN TH DEVELOPMENT OF CS2, OTHR THN BEING PGE'S PARET CORPORATION? Yes. On May 4, 1999 Enron ordered the turbine for CS2 from GE at a contract pnce of $35,889,000. HOW DID A VISTA BECOME INOLVED WITH CS2? DIRCT TESTIMONY OF DENNIS E. PESEAU - 7 IPUC Case Nos. A VU-E-4-1 and A VU-G-Ø1 ..................(... i A.In mid-1999, Enron and PGE decided to sell CS2. On October 4, 1999, Avista Power 2 entered into an "evaluation agreement" with PGE that allowed it to begin its due 3 diligence investigation of the plant. I assume that other potential buyers were also 4 investigatig the purchase at about the same time. 5 Q HOW WAS THE PROPOSED SALE STRUCTUD? 6 A.By the tie it was completed, the deal was classic Enron in its quirkiness. On October 1, 7 1999, three days before Avista Power signed its evaluation agreement, Enron 8 incorporated Coyote Springs 2, LLC ("LLC") as a wholly owned subsidiar. On 9 December 22, 1999, Enron and PGE agreed to transfer CS2 to LLC, contigent upon a 10 subsequent sale to an unidentified third par. The December 22nd agreement also 11 divided up the proceeds of the potential sale as follows-both PGE and Enron would first 12 recover their "cost basis" in CS2 and the tubine, plus their out of pocket ánd allocated 13 costs of development. Thereafer, the fit $10.47 millon of profit was allocated to PGE, 14 the next $12 millon to Enron, and any additional amounts were to be split. 15 Q.DID THS PGE AN ENRON DEAL CONTEMPLATE A SALE TO AVISTA 16 POWER? / 17 A.Not originally. Apparently it was strctued for a sale to an undentified third par who 18 ultimately backed out. Then Avista Power re-entered the picture. On March 4,2000, 19 Avista Power signed a Letter of Intent ("LOI") with Enron to buy both CS2 and the 20 tubine. The LOI set the purchae price at $19.5 millon for CS2, and $40 milion for the 21 tubine. PGE's and Enron's collective cost basis and development costs for CS2 were 22 identified as $ 8,450,000, with the remainig $11,050,000 labeled as a "premium." 23 Q.WHT DID AVISTA POWER INTEND TO DO WITH THE CS2 PLANT? DIRCT TESTIMONY OF DENNS E. PESEAU - 8 IPUC Case Nos. A VU-E-Ø4-1 and A VU-G-61 ..................l.... 1 A. 2 3 4 5 Q 6 A. 7 8 9 10 11 12 13 14 15 16 17 18 Q. 19 A. 20 21 22 23 As in the case of the Rathdr plant, A vista Power presumably intended to operate CS2 as a merchant plant sellig into Western wholesae electrcity markets. I base ths presumption in par on the plant's location, which is il suited to serve Avista Utilties 10ad centers that are located far to the east of CS2. DID TH PURCHASE CLOSE AS PLANED? No. On June 20,2000, the LOI was amended to reallocate the purchase price as $16.5 milion for CS2 and $43 milion for the turbine. I canot find an explanation for ths change in any of the discovery documents we received, although I surse it may have been the result of a reduction in the previous estimate of development costs. An even stranger development took plac approximately thee weeks later, on July 7, 2000, when Enron assigned its rights to the GE tubine to Avista Power. On the same day, Enron created another subsidiar, LJM2-Coyote ("LJM"). For a price of $3,540,000, LJM2 provided A vista Power with a two week "put option" on the tubine. In other words, from July 7t1 though July 21 st, A vista Power could require LJM to repurchase the tubine for the sum of$39,960,000. This put option was never exercised because, on July 21,2000, Enron assigned its interest in LLC to Avista Power, thus giving A vista Power ownership of CS2 as well as the tubine. WHY is TH LJM2 TRASACTION STRNGE? I can think of no legitimate business reason for A vista Power to enter into the put option agrement. In the first place, tubines were in short supply at the time, and A vista would have had little diffculty re-sellng the tubine if the CS2 deal somehow collapsed. Moreover, it is difficult to understad why, if Avist Power feared the exposue of holdig the tubine before it secured the CS2 rights, it didn't simply insist on a DIRCT TESTIMONY OF DENNIS E. PESEAU - 9 IPUC Case Nos. A VU-E-04-1 and A VU-G-04-1 ...................!.... 1 2 3 4 5 6 7 8 Q. 9 10 A. 11 12 13 Q. 14 A. 15 16 17 18 19 20 Q. 21 A. 22 simultaneous transfer of the two components. Instead it allowed Enron to impose a twO- week gap on the signng of the two agreements and, in effect, sell it $3.5 millon of insurance to cover the miimal exposure tht gap created. Finally, why would any reasonable businessperson pay $3.5 millon for a two week "insurance policy" issued by an empty corporate shell, with no assets and an operating history ofless than a day, even ifEnron guateed the put? Ths simply doesn't pass even a minimal smell test, paricularly when the counter pary is naed Enron. WHEN ALL WAS SAID AND DONE, WHAT DID A VISTA PAY FOR CS2 AN TH TUIN? The total purchae price, includig the option, was approximately $59.5 millon, for a plant that, by my calculations, appeared to have an all-in cost of approximately $42 millon. WHT WAS THE BOOK VALUE OF TH TRANSFERRD ASSETS? The book value of the tubine would have been the same as its purchase price, $35,889,000. The A11ocation Agreement dated July 21, 2000 listed CS2's book value as $3,755,409, with an additional $2,287,591 allocated to project development expenses. Consequently, the book value would have been $39,644,409 without the development expenses, and $41,932,000 if development expenses were capitalized and added to book value. WAS THAT TH END OF AVISTA POWER'S INVOLVEMENT WITH ENON? Not quite. In April of 2002, CS2's prie contrctor, another Enron afliate, fied for banptcy and CS2 lost the benefit of its fixed price consction contract while at the DffECT TESTIMONY OF DEN E. PESEAU - 10 IPUC Case Nos. A VU-E-01 and A VU-G-84-1 1 2 3 Q. 4 5 A. 6 7 8 9 10 11 12 13 14 15 16 17 18 Q. 19 20 A. 21 22 same time incurng the cost of replacing the prie contrctor and setting with subcontrtors. WAS THAT TH ONLY PROBLEM THAT OCCURRD DURING TH CONSTRUCTION AND OPERATION OF CS2? No. It is fair to say tht CS2 has been, and continues to be, an economic and operationa nightme. In May of2002, approxitely a month before the scheduled completion of the plant, a fire destroyed the tranformer purchaed from a Turkish supplier. This not only prevented the completion of the plant, it also resuted in an environmenta incident when water used to douse the fire overran the splash pond built to contai the transformer's contents in the event of an accident Clean-up costs as of December 31, 2003 were approximately $1.7 milion, half of which are Avista's responsibilty. A replacement trasformer arved at the site in December, 2002, but an inpection revealed it could not be instaled because of shipping damage. Repairs to this transformer delayed CS2's commercial operation date for more than a year, to July, 2003. Thereafer, the plant was in service for approxiately six months. It then experienced another round of transformer problems that shut it down again. The projected date for a retur to service is now August of2004. YOU JUST DESCRIBED CS2 AS AN ECONOMIC NIGHTMAR. AR YOU REFERRG TO SOMETHG BEYOND ITS CONSTRUCTION PROBLEMS? Yes. The constrction problems have caused the estimated cost of A vista's haf of the plat to swell from approximately $94 milion to $109 millon. In addition, the natual gas swaps I will discuss in detail later in my testimony produced losses in excess of $62 DIRCl TESTIMONY OF DENNIS E. PESEAU - 11 IPUC Case Nos. AVU-E-4-1 and AVU-G-01 1 2 3 Q. 4 A. 5 6 7 8 Q 9 10 A. 11 12 13 14 15 16 17 Q. 18 A. 19 20 21 Q 22 millon. The bottom line is that A vista overpaid for the plant in the original purchase, and every tum of the cards since then has only added to the misery. so WHO PAYS FOR ALL THIS?' Under Avist's proposal "to rate base the entirety of the plant's cost, Avist ratepayers will pay for all of these problems. If Avista's proposal is accepted, the only entities tht wal away from ths trn wreck uncathed are the plant's origial owner, Avista Power, and its parent, A vista Corpration. HOW DOES A VISTA POWER ESCAPE ANY RESPONSIBILITY FOR CS2'S PROBLEMS? In December of 2000, A vista Corporation anounced it would acquire CS2 from Avista Power. But it did not in fact follow though on this anouncement. Instead, it vacilated. Internal A vista memos indicate that A vista Power was tring to sell the entire plant to third pares in the suer and fall of 2001. But A vista Power received only one ful price offer from Mirant, and that prospective deal fell apar when Mirant ran into cash flow problems. Ultimately, Avista Power ended up sellng 50 percent of the plant to Mirt, and 50 percent to A vista Corporation. WHEN DID THESE SALES OCCUR? Avista Power assigned a 50 percent interest in LLC to Mirat on December 12, 2001. But it did not transfer the other 50 percent of the plant to A vista Corporation until Janua 1,2003, afer the close of the test year in ths case. GIVEN THS HISTORY, WHT IS TH APPROPRIATE RATEMAG TRATMNT FOR CS2? DIRCT TESTIMONY OF DENNIS E. PESEAU . 12 IPUC Case Nos. A VU-E-04-1 and A VU-G-01 1 A. 2 3 4 5 6 7 8 9 10 11 Q. 12 13 A. 14 15 16 17 18 19 20 21 22 23 I have two recommendations concernng CS2. The first is that the cost of the plant should not be included in rate base in ths case. CS2 is demonstrably not used and useful, and its trck record does not inspire confdence it will be used and usefu in the near futue. Avist ha had thee tres at completing the plant and gettng it rug on a reliable basis. It has strck out all thee ties. Given ths history, the plant's costs should not be eligible for recovery in regulated rates until it ha a demonstrated track record of usefulness and reliabilty. Furennore, if and when the plant does become eligible for inclusion in rate base, the rate based costs should be limted to the plant's fair market value, as descnbed below, as of the transfer date of Janua I, 2003. WH ARE YOU PROPOSING TO REDUCE THE PLAN'S COST IN THIS MAR? I am simply applying stdard ratemag precepts to the purchase. A vista Power is an. unegulated Avista Corporation subsidiar, and tranactions between it and Avista Corporation are clearly not at an lengt. I am not an attorney, but I have spent enough years in the regulatory field to state that, in jurisdctions I am familar with, when a utility purchases goods or services from an umgulated afliate, the burden is on the utility to prove tht the purchase pnce did not exceed fair market value. In the present case, because of alI the constrction disasters, it is quite clear that transferrng CS2 to A vista Corporation at cost creates a purchase pnce that is well in excess of fair market value. These excess costs should be disallowed. It is patently unjus to ask the ratepayers to relieve A vista Power of the unortate consequences of its half ownership ofCS2. DIRCT TESTIMONY OF DENNIS E. PESEAU - 13 IPUC Case Nos. A VU-E-04-1 and A VU-G-04-1 1 Q. 2 3 4 A. 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Q 22 A. 23 DOES THE FACT THAT AVISTA CORPORATION PREVIOUSLY ANNOUNCED AN INTENTION TO ACQUIRE THE PLANT MA ANY DIFFERENCE IN THS CASE? No. A vista's anounced intentions came afer A vista Power had already overpaid for the assets it purchaed from PGE and EnOll so an adjustment to fair market value would have been in order even then. In addition, even though the boards of directors of the involved companies authonzed their executives to proceed with the tranaction, the companies never acted on those resolutions. Avist's discovery responses contan no contrct, memorandum of understding, or any other document that would evidence an intention to proceed with the sale. Under those circumstances, A vist Power was under no legal obligation to sell to A vista Corpration, and it in fact tred to sell the plant to thrd paries month afer the anouncement. Eventuly it did sell half to Mirant. Avist unlaterally chose to purhase CS2 though its unegulated subsidiar, thereby avoiding any regulatory constraints on its use or disposition of the assets. Let us suppose tht Avista Power had succeeded in the sumer of2001 in selling the plant at a Pl'fit. Would Avista Power have volunteered to share the proceeds with the ratepayers just because at one time it intended to sell the plant to Avista Corporation? Ths is the same A vista that resisted shang the Centralia sale proceeds with ratepayers. A vista would have argued tht the deal was never consumated, and tht ratepayers never acquired an equitable interest in the plant though the payment of depreciation. HOW DO YOU PROPOSE TO DETERME THE FAI MARKT VALUE OF CS2? The Commssion could conduct fuer proceedings for the express purose of makng such a determnation, but there is a much easier metod readly available. Just two years DIRCT TESTIMONY OF DENNS E. PESEAU -14 IPUC Case Nos. AVU.E-4-1 and AVU-G-01 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Q. 15 16 17 A. 18 19 20 21 22 ago, the Commssion conducted an extensive investigation to determine the cost of a 270 megawatt combined cycle natual gas plant to use as a suogate avoided resource ("SAR") for the purose of calculating avoided cost rates. On August 2, 2002, one month afer CS2's origina scheduled completion date, and five months before the trsfer of CS2 to A vista Corporation, A vista filed rebutt testmony identifying the most recent constrction cost estimates for the SAR as $604/klowatt. I see no reason why A vist should not be held to its own contemporaeous estiate of the cost of constrcting a plant nearly identical to CS2. This figue, after all, represents the maxmwn value A vista Corporation was willng to pay for the purchase of resources from unelated thrd paries just before it acquired CS2 from A vista Power. Using the $604 figue produces a fair market value for CS2 of $84,560,000 for Avista's share of CS2. The Commission should not allow costs above ths amount in rate base at any time. The Natural Gas Hedges WHAT is TH ISSUE WITH RESPECT TO THE "DEAL A" AN "DEAL B" HEDGE TRSACTIONS IN THE COMMISSION'S ORDER ON AVISTA'S 2003 PCAFILING? To its credit, the Commssion recognzed the peculiar nature of both Deal A and Dea B in the 2003 PCA proceedig and deferred a decision on the cost of these deals into the present genera rate case. As I explai below, the high costs associated with each deal ate the result of imprudent decisions and self-dealing between A vist Corpration and Avist Energy. Avista's actions have resulted in excess natual gas costs of more than $62 milion on a system-wide basis. DIRCT TESTIMONY OF DENNIS E. PESEAU . 15 IPUC Case Nos. A VU-E-4-1 and A VU-G-041 1 Q.HAVE MOST OF THE INORMTION, DATA, AND FACTS NECESSARY TO 2 UNDERSTAND THE NATUR OF DEAL A AND DEAL B BEEN TRATED AS 3 CONFIDENTIAL BY AVISTA? 4 A.Yes. Ths is unfortate, as most of the confdential trading data necessar to understad 5 Deal A and Deal B are public and available on the FERC website as par of the FERC's 6 show-cause proceeding that culated in its March 2003 P A02-02 report Final Report 7 on Price Manpulation in Western Markets. There is, therefore, no valid reason to 8 continue to treat historica trding data as confidential. 9 Q.WHAT IS THE DIFFERECE BETWEN TH NATURL GAS TRNSACTIONS 10 OF DEAL A AND DEAL B AND NORM NATUL GAS TRASACTIONS? 11 A.There are at least thee distinct aspects of the Deal A and Deal B transactions tht ar 12 peculiar. The first distinction is that the Deal A and Deal B trades were financia as 13 opposed to physical tranactions. 14 Q.WHT IS THE DISTICTION BETWEN NATUL GAS FINANCIA AND 15 PHYSICAL TRANSACTIONS? 16 A.A physical traction is the more norm and common purchase of an actual, physical 17 quatity of natual gas at specified pricing, tenns and conditions. In physical gas 18 transactions, there are no winners or losers. The buyer receives a specific quatity of gas 19 at agreed upon pricing tenns. The seller receives a payment for providig the physical 20 gas to the buyer. 21 A financial natual gas transaction involves no actua exchange of physical gas. 22 Instead, a financial deal is agreed upon by buyer and seller in which the buyer bets that 23 futue gas prices will increase, while the seller bets that futu gas prices will decrease. DIRCT TESTIMONY OF DENNIS E. PESEAU - 16 IPUC Case Nos. A VU-E-04-1 and A VU-G-01 ,............"...-... 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Q. 20 A. 21 22 Q. 23 24 25 A. 26 Depending upon the futue monthly movement of gas prices, the loser, or the counterpar on the wrong side of the bet wrtes a monthly check or "settles" with the other par. The FERC report just referenced defies financial gas swaps similar to Deal A and Deal B as: In a swap, two counterpares execute a trade in which the buyer pays a fixed, known pnce for some notional quatity of gas and the seller pays a pnce that will var with the market pnce (generaly based on some agred upon pnce index), which will only be known later. Thus, the buyer in a swap transaction is going long - makng a bet that the market price will nse - and the seller is bettng that pnces will fall. (page II-51) On the four days Apnl 10, Apnl 11, May 2 and May 10,2001, Avista Energy entered into tie financial swaps, Deal A and Deal B, on behaf of A vista Utilities that were of unprecedented length and lost over $62 millon for ratepayers. At no time dunng the term of these two deals were these ficial trdes "in the money," or profitable for A vista Utilties. The deals were extordinanly profitable for the thee seller counterparies. WHO WERE TH COUNTERP ARTIES TO THESE TRSACTIONS? BP and Miant were the counterparies on Deal A. Incredible as it may seem, A vista Energy was the counterar for Deal B. WHY WOULD THE SAM ORGANIATION SIMLTANEOUSLY TAK OPPOSITE SIDES OF THE BET ON THE DEAL B SWAP? ISN'T THS A "ZERO SUM GAME?' The fact tht the PCA protected A vista Corpration is the only thng that made this an attactive traction for Avist Corporation. The PCA insulated the shaeholders of the DIRECT TESTIMONY OF DENNIS E. PESEAU - 17 IPUC Case Nos. A VU-E-041 and A VU-G04-1 ..................r.... 1 2 3 Q. 4 A. 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Q. 20 21 A. 22 23 parent company by passing. though to ratepayers the excess of the locked in hedged natual gas prices over and above the actual market prices tht existed at the time. MIGHT THS BE SIMLY A CASE OF BAD LUCK FOR AVISTA'S CUSTOMERS? No. The only maner in which a financial swap can be consumated is with a willng buyer and a willng seller. The reason for entering a swap on either side is because one's inormation on market pricing makes the risk of this bet wortwhile. Again, the only possible reason for Avista Utilities to buy the long-ter financial swap that it did was because it was predicting gas prices would continue to increase. If futue gas prices at the time the swap was entered were expected either to remai at the then high levels, or to decrease then entering the fixed price swap could only har the buyer. On the other side, the seller A vista Energy apparently had information suggesting that future gas prices were not going to rise above the agreed upon price per decatherm over the subsequent 17 months, or it would have been foolish to sell the swap. Unless A vist Energy based its action on information that prices would either remain at their high levels or fall, it would have been acting diectly agaist the best intersts of its shareholders. If natu gas prices trly were expected to increase over the subsequent 17 month, the best action for both A vista Utilities and A vista Energy would have been for A vist Utilities to buy the fixed-price swap from a less informed counterpar. is THERE ANYTHING ELSE UNSUAL ABOUT AVISTA CORPORATION'S DECISION TO MAKE THE SWAP? Yes. At the time, A vista Energy brokered all of the natural gas and electrc tres made for the benefit of A vista Utilities. Avista's justification for ths practce was tht A vist Energy's continuous maket parcipation provides it with market insights and knowledge DIRCT TESTIONY OF DENNIS E. PESEAU - 18 IPUC Case Nos. A VU-E-041 and A VU-G-1 1 2 3 4 5 6 7 8 9 Q. 10 A. 11 12 Q. 13 14 A. 15 16 17 18 19 20 Q. 21 tht the utilty division doesn't have. Avista Energy's role as a broker for the utilty division placed it in a fiduciar position that required it to disclose the fact that it considered Deal B (and by implication, Deal A) to be a bad deal for Avista Utilties. If A vista Energy did disclose tht fact and the additional fact that it wa tang the other side of the swap, it was obviously imprudent for Avista Utilities to proceed with swaps tht the par with superior knowledge regarded as foolish. If Avista Energy did not disclose its role, then it violated its fiduciar responsibilties, and that alone would be grounds for disallowing the cost of both deals in rates. WHT WAS THE RESULT OF THE DEAL B SWAP WIH AVISTA ENERGY? The result was tht A vista Utilties immediately began monthy transfers of what tured out to be millons of dollars to Avista Energy. HOW COULD THERE BE AN IMMDIATE TRNSFER OF CASH? I THOUGHT THE SWAP WAS FOR GAS TO BE DELIVERED IN THE FUTU. The immediate impact occured because of the way financial trades such as this are setted. As I stated earlier, swaps like ths are literally bets on the direction of prices. Consequently, they sette monthy based on the futues price of gas for the time period covered. In any month in which the futues price is less th the fixed price, the buyer (Avista Utilities) loses his bet and must cut a check to the seller (Avista Energy) for the difference. i WHT IS TH ULTIMTE SIGNIFICANCE OF THE WAY THESE TRAES AR SETTLED? i A vista converted Deal B to a physical purhase at an equivalent fixed price on June 20, 2~2. DIRCT TESTIMONY OF DENN E. PESEAU - 19 IPUC Case Nos. A VU-E-4-1 and A vu-G04i 1 A.It explains why the Commission really ha no choice but to disallow Deal B. Any other 2 decision would provide Idaho utilities tht have a PCA or PGA with a blueprint on how 3 to raid ratepayers' pockets for the benefit of shareholders. 4 Q.HOW DOES AVISTA UTILITIES ATTMPT TO mSTIY ITS DECISION TO 5 ENTER INTO "BUYS" IN BOTH DEAL A AN DEAL B? 6 A.Avista witness Mr. Lafert discusses these two deals (actuly four transactions) in 7 pages 29-56 of his testmony. The attmpted jusification, while sometimes repetitive, is 8 outlned as follows: Deal A and Deal B were made because: 9 1.A vista was in an electrc resource deficit or a "short-positi~n" durg the hedge 10 periods. (pp. 31-32,37-40,42-47) 11 2.The high hedge prices of Deal A and Deal B still compared favorably to forward 12 market prices of electrc purchases at the time. (pp. 32-36) 13 3.Electric market prices in Janua-May 2001 were high, and federal opposition to 14 price caps suggested no relief in market prices. (pp. 40-42, 41-42) 15 4.The 36 month and 17 month duration of Deal A and Deal B were not unusual terms 16 for company hedges of ths sort. (pp.48-52) 17 5.The company did not expect tht forward natual gas prices would decline as they 18 did. (pp. 52-53) 19 6.The terms of Deal A and Deal B were consistent with market conditions on April 10 20 and May 10. (pp. 53-54) 21 Q.WOULD TH DEFICIT ELECTRIC RESOURCE POSITION IDENTIFIED BY THE 22 COMPANY mSTIFY BUYG FINANCIA HEDGES LIKE DEAL A AN DEAL 23 B? DIRCT TESTIMONY OF DENNIS E. PESEAU - 20 IPUC Case Nos. A VU-E-041 and A VU-G1 1 A. 2 3 4 5 Q. 6 7 A. 8 9 10 II 12 13 14 15 16 17 Q. 18 19 A. 20 21 22 23 No. I fist want to make clear that Potlatch does not want in any way to discourge appropriate resource acquisitions to maintai the reliabilty of serice to customers. However, I am quite surrised that the company testimony in ths regard suggests that somehow Dea A and Deal B in any way assiste in covering a resource-short position. WHY DO YOU INDICATE THAT DEAL A AND DEAL B DID NOT ASSIST A VISTA IN COVERIG AN RESOURCE DEFICIT? Fincial fixed-for-floatng swaps such as Deal A and Dea B never provide for any physical quantities of natul gas. Again, Deal A and Deal B are strctly the tag of "price positions" between two pares, a buyer and seller. For example, if! thought that natual gas prices were going to increase in the near-tenn, and I could locate a pary thinkng the opposite, I could buy a natu gas fincial swap and reap gais or sufer losses according to my accuracy, and never be involved with actu physical quantities of gas. If I need natual gas to close an electrc resource deficit, I would need to enter into distict physica gas contrac as a buyer. Deal A and Deal B did not entitle A vista to even a molecule of methane. IF A VISTA NEEDED ADDITIONAL NATUL GAS SUPPLY TO COVER TH PERCEIVED DEFICIT, HOW DID IT ACQUIRE SUCH SUPPLIES? The company on March 13 and March 22, 2001, entered into 36 month and 17 month physical trades for 27,658 and 20,000 decathenns per day at market index-based prices. These two gas contrts alone filled the need to cover the resource deficits discussed by the Company. Dea A and Deal B merely expressed the perceived dirction that natual gas prices would tae over the ensg 36 and 17 month periods between the bettng DIRCT TESTIMONY OF DENNIS E. PESEAU - 21 IPUC Case Nos. A VU-E-04-1 and A VU-G-01 ...................,,.................. 1 2 ' 3 Q. 4 5 6 A. 7 8 9 10 11 12 13 14 15 Q. 16 A. 17 18 19 20 21 22 23 pares. The Commssion should reject any notion that these fiancial swaps can be peddled to customers on the basis of enhcing system reliabilty. WHAT DO YOU MAKE OF MR. LAFFERTY'S DISCUSSION ON PAGES 32-36 OF HIS TESTIMONY THT SUGGESTS TH DEALS WERE PRUDENT BASED ON THE THE FORWAR MARKT PRICES? The analysis at pages 32-36 of Mr. Lafery's testimony attempts to demonstrate that the varable cost of power produced by Avista's generators would have been below the predcte futue market power prices at the gas prices in Deal A and Deal B. That is, A vista was predicting that at the Deal A and Deal B fixed swap prices, buying gas for internal generation would be cheaper th buying on the electrc market. This assumes, of course, that the existing forward power prices at mid-Columbia represented a good predictor of actual prices in the futue. While this anysis is mathematically correct, it hardly demonstes that the Deal A and Deal B trades were prudent. PLEASE EXPLAI. The analysis presented is the stag point for an "arbitrgen trade. An arbitrage is the simultaneous buying and sellng of fugible commodities in different market in order to mae an imediate, riskless profit. For clarfication of the proper use of Mr. Laferty's analysis I refer to the Coyote Spnngs 2 table at the bottom of page 32 of his testiony. The first row indicates tht the Deal B gas fixed price is $6.56 per decather and, at the CS2 plants' heat rate, Deal B gas could produce electrcity at a varable cost of $46.06/MWh. The forward electrc prices, according to Avist, showed power prices at the tie of$126.75 and $105.38/MWH. DlRcr TESTIMONY OF DENNIS E. PESEAU - 22 IPUC Case Nos. A VU-E-04-1 and A VU-G1 1 2 3 4 5 6 Q. 7 8 9 A. 10 11 12 13 14 Q. 15 16 A. 17 18 19 20 21 22 23 A power trader facing these circumstances would, if the market held, simultaeous lock in a buy at the $6.56 gas price and a sae at the $126.75 and $105.38IMWh electric prices to insure a riskless profit equa to the difference between these two energy sale pnces and the $46.06/M the electrcity would cost to produce. This would be a rational use of Mr. Lafert's analysis. DOES TH ANALYSIS PRESENTED BY MR. LAFFERTY DEMONSTRATE THT DEAL A AND DEAL B WERE PRUDENT AT TH TIM FOR THE PURPOSE OF PROTECTING RATEPAYERS? No. Unlike the arbitrage case where a certin outcome (the riskless profit) is locked in by a conscious decision to forego possible upside and avoid all downside, the open hedges conducted by Avista did the opposite. Avista's hedges in essence locked in the downide - by fixing gas prices at near record levels for up to 36 month - and precluded the ratepayers gettng any upside if gas pnces retued to more normal historic levels. WOULD AVISTA ENERGY HAVE ENTRED TH SELL SIDE OF THESE HEDGES IF IT EXPECTED NATU GAS PRICES TO CONTIUE UPWAR? Absolutely not. Doing so would have been a direct contradiction of management's fiduciar responsibilty to shaeholders. A vista Energy made a calculated bet that the very high natual gas maket prices could not be sustaned. By sellng Deal B to the utility for prices that exceeded $6.00/decatherm it stood to reap all the profit from falling pnces. If prices simply remained at the then high levels, A vist Energy stood to 10se nothing. Only Ü gas prices increasd fuer from these high levels, did it risk losing money. The end result is tht A vista Energy made an obvious bet and reaped more than $18 millon in benefits from its parent utlity. DIRCT TESTIMONY OF DENN E. PESEAU - 23 IPUC Case Nos. AVU-E-04-1 and AVU-G-4-1 ............................ ...... ..................................... ........................................................... ................-............................................ ....... .... .................................................. 1 Q. 2 3 A. 4 5 6 7 8 9 10 11 12 13 14 15 16 Q. 17 18 19 A. 20 21 22 23 PLEASE ADDRESS MR. LAFFERTY'S DISCUSSION ON PAGES 40.42 REGARING TH PRUDENCE OF THESE TRASACTIONS. Beginnng on line 17 of his page 40, Mr. Lafert suggests that a pnident person would have viewed the high winter prices of2000.2001, and the federal governent's position against the implementation of price caps, as reasons to "go long" with the natual gas hedges. I have just two short comments on this point. First, the pnident man at A vista who was buying the fixed-price hedge on behaf of the utilty wa the same man who was sellng it on behalf of A vista Energy. Takng simultaeous and opposite positions on the same tranaction caot each be deemed pnident. The same market observation of high prices and price caps could not have led a single individual or committee to opposite conclusions regarding the futue near-term trend in gas prices. Second, other utilities and market parcipants in the western U.S. observed the same market phenomena discussed by Mr. Lafert and did not tae long-term price positions tht anticipated fuer gas price increases. PLEASE DISCUSS MR. LAFFERTY'S TESTIMONY ON PAGES 48-52 THAT SUGGESTS THAT TH 36 MONTH AN 17 MONTH HEDGES ARE COMMONLY MADE BY THE UTILITY. Mr. Lafert's discussion here involves only physical resource acquisitions, not fiancial hedges. I certnly agre with him that any resource portolio should have varous short medium, and long-term resources. In ths light, I do not cha1enge or tae issue with Avista's enterig into its March 13 and March 22 long-term physical gas purchase contrct, as I previously noted. DIRCT TESTIMONY OF DENNS E. PESEAU - 24 IPUC Case Nos. A VU-E-041 and A VU.G-01 The issue here, of coure, is that A vist took an unprecedented long-ter price 2 view in the form of finacial hedges and, in combination with its subsidiar A vista 3 Energy, Avista Corporation, took both sides of the transaction. Mr. Lafferty is silent on 4 these points. 5 Q.HAS AVISTA EVER, TO YOUR KNOWLEDGE, ENTERED INO FINANCIA 6 HEDGES AS LONG AS THE 36 MONTI AND 17 MONT TERMS OF DEAL A 7 ANDEALB? 8 A.No. In response to Potlatch's data requests, Avista provided a list of all recent financial 9 hedges and fixed price contracts. Of the 67 fixed-price tranactions provided, the 10 overwhelmng majority of the contracts were for terms of 1-3 months, with a few with 11 terms of one year. Only the Deal A and Deal B trsactions were for such long periods. 12 I conclude that it is not Avista's normal business practce to enter into long-term price 13 hedges. 14 Q.HAVE YOU REVIEWED OTHR DATABASES FOR INORMA nON TO 15 DETERM WHTIER TH 36 AND 17 MONT TERMS OF DEAL A AND 16 DEAL B AR COMMONPLACE IN TH INUSTRY? 17 A.Yes. In conjunction with its investgation of electrc and natual gas prce mapulation 18 in western U.S. markets, the FERC compiled massive databases regarding both physical 19 and fiancial natual gas tres. As a check on the frequency of long-term fmancial 20 hedges, I reviewed the FERC data fie for all natual gas financial hedges that were 21 entered into dwig May 2001, the sae period as Deal A and Deal B. 22 Accordig to the data base file, there were 37,472 such transactions durng May 23 2001. The huge preponderace of these fiancial hedges was for the immediate month or DIRCT TESTIONY OF DENN E. PESEAU - 25 IPUC Case Nos. A VU-E-04-1 and A VU-G-1 1 2 3 4 Q. 5 6 A. 7 8 9 10 11 12 13 14 15 16 17 18 Q. 19 20 A. 21 22 quarer ahead, although some were for quaerly periods endig as late as December 2002. I found no other financial trades that extended as long as the 36 and 17 month term contaed in Deal A and Deal B. PLEASE ADDRESS MR. LAFFERTY'S TESTIMONY THAT TH DECLINE IN NATUL GAS PRICES WAS UNFORESEEABLE. Mr. Lafert's testmony on pages 52-53 states that ''te Company" did not expect that forward natual gas prices would decline, as of course they did (Page 52, lines 3-6). I canot from the context of the sttement ascertain just what ''te Company" is. Certinly, A vista Energy expected a decline in natual gas prices, or it would not have sold the fied price swap. Furer, Mr. Laffert's explantion does not justify the utility buying the swap. As I explaied earlier, buying the fied-price swap only gave the utiity protection from fuer increaes in gas prices, not from the then existing level of high prices. Mr. Laferty explais only that". .. the Company expected the price for natual gas would remain high for some time into the futue..." (page 52, lines 5-6). He does not make the arguent that the Company expected gas prices to continue to increase, which would be the only legitimate reason for the swaps. WERE THE TERMS OF DEAL A AND DEAL B CONSISTENT WITH MAT CONDITIONS ON APRIL 10 AND MAY 10,2001, AS MR. LAFFERTY ARGUES? As I have previously indicated, there were apparently no other natu gas hedge tranactions occurng tht were comparable to Deal A and Deal B. The references Mr. Lafert makes to forward price cures at that time certainly is no indication of what an DIRCT TESTIMONY OF DENNS E. PESEAU - 26 IPUC Case Nos. AVU-E-041 and AVU-G04-1 ..... ..........,.............'.... . 1 ar-lengt buyer and seller might agree upon for financial hedges of up to 36 month in 2 length. 3 Q.WHT is YOUR RECOMMNDATION WITH RESPECT TO TI FINANCIAL 4 LOSSES CLAIMED BY TH UTILITY IN CONJUCTION WIH DEAL A AND 5 DEALB? 6 A.The fmancial losses incured by the utilty in Deal A and Deal B are sumarzed in my 7 Exhbit No. 202. As of March 31, 2004, the cumulative losses to the utility on the hedges 8 were $62,446,000. These losses represent the difference between what the utility would 9 have paid for natu gas on the maket (absent the hedges) and the high fixed gas price 10 tht it agreed to pay by virtue ofthe hedges. The market prices for gas are shown for the 11 Malin receipt point, and are compared to the weighted average price of the hedges, 12 labeled "Average $/dt." For Deal A, the cumulative financial loss was $44,175,600. For 13 Deal B, the cumulative loss wa $18,270,400. 14 Since Deal B involves self-dealing and a direct trfer of the utilty's losses to 15 shareholder profits, the entie $18.3 milion must be disallowed, adjusted of coure for 16 the Idao jursdictional share and for the PCA test period. Deal A did not involve self 17 dealing, but it wa certy imprudent and it is fuer suspect due to the unprecedented 18 term of 36 month and the high locked in prices. I believe it should likewise be 19 disallowed. But if the Commssion for some reason rejects ths proposal, I propose, in 20 the alternative, a lesser adjustment based on a more norm hedging strategy. 21 Q.PLEASE EXPLAIN THE LA TIR RECOMMNDATION. 22 A.Deal A represents two hedge contrcts of 10,000 decatherms each for a perod of 36 23 months. The naed counte paries to these Deal A contrts are private entities with no DIRCT TESTIMONY OF DENNI E. PESEAU - 27 IPUC Case Nos. A VU-E-4-1 and A VU.G-04-1 1 2 3 4 5 6 7 8 9 10 11 Q. 12 13 A. 14 15 16 17 18 19 Q. 20 A. 21 22 23 apparent legal connection to Avista. According to the Company's response to Potlatch's data requests, A vista did not have either of these entities "sleeve," (conduct the trade for Avista Energy's benefit) the trsaction. Thus, there was no apparnt enchment of Avista's shaeholders. But Deal A was neverteless an imprudent $44.2 milion hedge given its duration and the fact that it was put on contr to A vista Energy's position. I base my adjustment on Avista's normal hedge strategies for all its other fied price gas purchases. As I stated earlier, Avista normally hedges for gas deliveries in ensuing seasons and occaionaly for periods as long as one year. If Avist had followed its normal hedging strtegy it would have avoided the disastrous 36 month Deal A fixed price of $6.45/decatherm. HOW is THIS INFORMATION USED TO CALCULATE AN ADJUSTMENT FOR DEAL A? My review of Avist's confdential information on other hedges reveals that Avist's normal hedges were established approxiately six month prior to a seaon (November- March or April-0ctober). I therefore used the Malin natural gas contract prices in effect six month prior to each upcoming season as a base price. For example, May 1, 2001 prices were used for the November 200l-March 2002 season. These prices are then subtracted from the Deal A prices. The results are sumard in my Exhbit No. 203. WHT DOES EXlITNO. 203 SHOW? That exhbit indicates tht, if Avista had not entered into Deal A and instead hedged in the same maner that it was hedging other natual gas purchases in the same tie frame, gas costs would have been $30,365,240 lower. I alternatively propose tht, should the Commssion not disallow the entiety of the Deal A costs, it should disallow $30.4 DIRCT TESTIMONY OF DENNIS E. PESEAU - 28 IPUC Case Nos. A VU-E-041 and A VU-G-01 1 2 3 4 Q. 5 6 7 A. 8 9 10 11 12 13 14 15 16 17 18 Q. 19 A. 20 21 22 23 millon of Deal A costs, adjusted for both the Idaho jursdiction as well as the PCA test period. The Test Year Mismatch YOU EARIER STATED THT AVISTA'S CASE CONTAINS A MISMATCH OF REVENUES AN EXPENSES. PLEASE EXPLAIN WHAT YOU MEAN BY THE WORD "MISMATCH." Avista calculates its test year revenues in a straightforward maer. Test year revenues consist of 2002 actu figues, "normalized" for weather and other stadard Commission approved adjustments. On the other side of the ledger, however, expenses and rate base are treated in a much different maner. Avista pro forms increases in selected expense items, such as pension, ince, and labor costs, to 2004 levels. A vista also includes in rate base a number of projects that were placed in servce afer the test year, as well as constrction work in progress that is scheduled for completion in 2004. These adjustments produce operating and maintenace increases of approximately $5.4 milion, rate base additions of $54 millon, and associated depreciation increases of $2.3 milion. The net effect is a mismatch of 2002 revenues agaist year-end 2004 expenses and rate base. IS THIS AN ACCEPTABLE RA TEMAKING PROCEDUR? No. For unown reasons, Avista chose a 2002 test year, rather th 2003. Having made that choice, it should not be allowed to unlateraly alter the test year relationship between revenues, expenses and rate base. It is a fudamenta principle of reguation tht a utility's rate bas and expenses should be matched against revenues for the same period. A vist's pro forma results clealy violate this priciple. DIRECT TESTIMONY OF DENN E. PESEAU - 29 IPUC Case Nos. A VU-E-04-1 and A VU-G041 1 Q.AR YOU SUGGESTING PRO FORMA CHANGES TO A TEST YEAR BASE CASE 2 SHOULD BE REJECTED OUT OF HAD? 3 A.No. Addig known and measurable changes to a test year base case is a legitimate 4 regulatory tool, but it must be used with extreme caution because of the high potential for 5 abuse. In a rate case, utilties have every incentive to identify changes that increase the 6 revenue requiement, but no incentive at all to find revenue enhancing changes. 7 Consequently, it comes as no surrise that all of Avista's proposed known and 8 measurable changes produce an increase in revenue requiement. These changes should 9 either be rejected or accompaned by a corresponding adjustment to revenUes. 10 Q.CAN YOU PROVIDE AN EXALE OF THE TYPE OF KNOWN AND 11 MEASURALE CHANGE THT SHOULD BE ACCEPTED? 12 A.The classic example is a post-test year change in ta rates. Plugging the new ta rates 13 into the revenue requirement calculation does not distub the relationship between test 14 revenues and expenses and is obviously equitable. 15 Q.WHT RULES SHOULD BE APPLIED TO POST-TEST YEAR KNOWN AN 16 MEASURALE CHAGES? 17 A.Post-test year expense and rate base adjusents should only be accepted when they are 18 in fact try known and measurable. In order to quaify, a proposed adjustment must be 19 virtually certin to occur, and its revenue requirement impact must be precisely and 20 reliably quatifiable. Furennore, there mus be some limit on the time interval between 21 the test year and pro fonna adjusents. 22 Q.AR AVISTA'S PRO FORM ADJUSTMENTS CONSISTENT WITH THE RULES 23 YOU HAVE JUST DESCRIED? DIRCT TESTIMONY OF DENNIS E. PESEAU - 30 IPUC Case Nos. A VU-E-04-1 and A VU-G-1 ................... 1 A. 2 3 4 Q. 5 A. 6 7 8 9 10 11 12 13 14 15 Q. 16 17 A. 18 19 20 21 22 No. In the case of its pro forma expense adjustments, the time lag between the 2002 test year and adjustments based on 2004 data or projections makes these adjustments inequitable. WHY is THE TIME LAG IMPORTANT? For most utilities, expenses tend to increase every year, but ths is offset in whole or in par by effciency improvements and load growt. If this were not so, utilties would automatically fie rate cases every year. Avista's own rate case history nicely ilustrates this point. Its last rate case occurred in 1998, and the one before that was several years earlier. Avista's pro forma expense adjustments for items like increased labor, insurance, and simiar cost are simply 2004 budget esates. It is absolutely inapproprate to match these expenses agaist 2002 revenues because normal load growt will recoup some or alI of these costs. The Commssion should either reject the 2004 adjustents or impute revenue increaes to the 2002 test year to correct ths mismatch. AR AVISTA'S PRO FORMA ADDITIONS TO RATE BASE SUBJECT TO THE SAME OBJECTIONS? Only in par. Additions to Avista's generating capacity were added to the power supply model, and ths preswnably adds revenues or decreases expenses as a result of the pro forma plant additions. I have not attempted to confrm that this modeling change was properly implemented, but I asswne Stawill do so. If the implementation was correctly done, I have no objection to these pro form adjustments as such, although i have proposed the removal of Coyote Springs 2 on other grounds, as discussed above. DIRECT TESTIONY OF DENNIS E. PESEAU . 31 IPUC Case Nos. A VU.E-4-1 and A VU-G-041 1 2 3 4 5 6 7 8 9 10 . 11 12 13 14 15 16 17 18 19 20 21 Q. 22 A. 23 24 25 26 27 Q. But there is no siilar revenue adjustment for the $26,300,000 in 2003 and 2004 transmission projects A vista pro forms into the rate base, even though these additions will also produce either additional revenues or operational savings. Like other businesses, utilities generaly do not make additional investents or increase their expnses uness they can generate additiona revenues and profits, either by serving additional customers, or by cuttg costs or increasing margins. There is no reason to assume ths is not the case here. The projected expenditues A vista has identified must be presumed to generate additional revenues or other benefits that would offset their costs, in whole or in par. Avista has made no attempt to identify these offsettng benefits. As the Commission pointed out in its recent order in the Idao Power rate case: Generally speang, the Commssion expects all utilties to attmpt to identify expense saving and revenue producing effects when proposing rate base adjustments for major plant additions. It is unfair to ratepayers to assume that the investment in these plants will not increase Company revenues or decrease Company expenses in the futue. Furer, it is uneasonable to expect the Commssion to allow ful recovery of plant investment as if the plant had been in operation the ful year without a corresponding adjustment to revenues and expenses. Order No. 29505, p. 7. HOW SHOULD THIS MISMATCH BE CORRCTED? There are basically the alterntive remedies available to correct ths rate base mismatch. The first would be to reverse the pro forma entres and properly match test year averages on both sides of the ledger. The second alternative is to update revenues to the 2004 level in the same maner as rate base and expenses. Finally, the thrd alternative is to employ the rate base adjustments the Commission adopted in the Idao Power rate cae. DO YOU HAVE A PREFERECE BETWEEN THSE THE ALTERNATIVES? DIRCT TESTIMONY OF DENNI E. PESEAU - 32 IPUC Case Nos. A VU-E-4-1 and A VU-e-64-1 A.As I have stated in other cases, I th anualizig revenues to 2004 year-end levels is the 2 preferable course for two reaons. First, it is much simpler to anuaize revenues than to 3 back out pro fonna adjustments from numerous expense and rate base categories. 4 Moreover, adjusting revenues produces a more forward-lookig result than reversing the 5 expense and rate base anuaizations. 6 I recognize, however, that the Commission adopted a third course of action to 7 correct similar nnsmatches in the recent Idao Power rate case. In that case, the 8 Commssion adopted a proxy for increased revenues and reduced expenses. Whle the 9 Commission stated that it did not necessary regard that adjustment as precedent for 10 futue cases, the circumstaces in ths case are very similar to the Idaho Power case. I 11 lack the precise data to calculate a simlar remedy of the mismatch in ths case, but I note 12 that in the recent Idaho Power decision the Commssion adjusted total revenues on the 13 order of 5 percent of the rate base additions. 14 Cost of Service Issues 1.5 Q.HAVE YOU REVIEWED AVISTA'S COST OF SERVICE STUDY AND TIE 16 RESULTIG RATE DESIGN? 17 A.Yes. The stuy sponsored by Ms. Tara Knox generally follows the methods approved in 18 the pas, with a major exception descrbed below. I recommend two improvements to 19 allocators contaned in the Company's study. 20 Avista's Proposed "Four Factor" Allocator for Common Costs 21 Q.DOES WITNESS TAR KNOX PROPOSE A CHAGE FROM TH PREVIOUS 22 APPROVED COST OF SERVICE METHODOLOGY USED IN CASE NO. WW-E- 23 98-11? DIRECT TESTIMONY OF DENNIS E. PESEAU - 33 IPUC Case Nos. A VU-E-Ø4-1 and A VU-G04-1 .. ..............'1 A.Yes. As noted on Pages 6.7 of her direct testimony, the Company proposes to allocate 2 "common costs" on the basis of four factors: direct O&M expenses, diect labor, net 3 direct plant, and number of customers. Previously, A vista had allocated these common 4 cost to customer groups with a 60% customer/40% energy allocation factor. 5 Q.WHT ARE "COMMON COSTS?" 6 A.Common costs are tyically defined as those costs necessar for the utilty to fuction, 7 but which are left over afer most directly assignable costs have been identified and 8 "fuctionaized" to production, tranmission, distrbution or customer accounts. These 9 remainig common costs include general and common plant investment costs and 1 0 admiistrative and general expenses. Offce buildings, future, transporttion 11 equipment, certin inventories, computer costs and a portion of mangement salares 12 typically comprise common costs. 13 Q.ARE TH SPECIFIC FOUR FACTORS USED BY MS. KNOX TO ALLOCATE 14 COMMON COSTS PARTIALLY VALID? 15 A.Yes and no. Yes, the four factors, if correctly defined, are legitite bases upon which to 16 allocate common costs. However, the method Ms. Knox uses to calculate the actual 17 weights of the four-factor allocations has a serious flaw, one that renders her calculations 18 highly volatile and incorrect. 19 Q.PLEASE EXPLAIN. 20 A.In order to better explain this issue, I list the proposed four factors chosen for the 21 common cost allocations: 22 23 24 25 1. 2. 3. 4. Direct O&M Expenses Dirct Labor Expenses Net Direct Plant Expnses Number of Customer DIRCT TESTIMONY OF DENNIS E. PESEAU - 34 IPUC Case Nos. A VU-E-4-1 and A VU-Gi 1 The issue I raise involves only one of the four factors - Direct O&M Expenses. Simply 2 put, Ms. Knox fails to remove a porton of these direct O&M expenses, an adjusent 3 that is necessar for the proper allocation of common costs. 4 Q.WHAT AR DIRECT O&M EXPENSES? 5 A.Direct O&M expenses in Avista's cost of service study are listed as FERC Accounts 500- 6 916 on pages 4-10 in Ms. Knox's Exhibit 16. Schedule 2. For reference, the sum of the 7 expenses in these O&M accounts is $97,699.000 (Line 369, Page 10 of 59. Exhibit 16, 8 Schedule 2). 9 By using the sum of all the dollars in all of the O&M accounts, and their 10 allocators (energy, demand, customer) as one ofthe four factors used, Avista and Ms. 11 Knox are suggesting that common costs are caused in a fashion similar to the cause of the 12 O&M costs. Properly defined, O&M expenses form a reasonable means with which to 13 allocate common costs. but Avista's O&M expense definition fails in ths regard. 14 Q. 15 IMPROPERLY DEFIND ITS DIRECT O&M EXPENSES AS ONE OF TH FOUR- WHAT IS TH BASIS FOR YOUR STATEMENT THAT AVISTA HAS 16 FACTORS TO ALLOCATE COMMON COSTS? 17 A.Thee distinct reasons support my conclusion that Avista's first factor, the Direct O&M 18 Expense, incorrectly allocates common costs: 19 1.Avista's O&M expense allocator is extremely volatile from year to year, 20 and common costs are not volatile. 21 2.Avista's anua common cost from 1998-2003 are actually inversely 22 related to its defition of O&M expenses. DIRCT TESTIONY OF DENNIS E. PESEAU - 35 IPUC Case Nos. A VU-E-01 and A VU-G041 2 3 4 5 Q. 6 7 8 A. 9 10 11 12 Q. 13 14 15 A. 16 17 18 19 20 21 22 23 3. A statistica regression analysis support the conclusion that the common cost allocator using A vista's Direct O&M Expenses is valid if, and only if, variable fuel and purchased power expenses are removed. Avista's Volatile Direct Expense Definition WHT is TH ISSUE WITH RESPECT TO THE VOLATILITY OF USING A VISTA'S DEFINITION OF DIRECT O&M EXPENSE TO ALLOCATE COMMON COSTS? Simply put, Avista's definition ofO&M expenses includes fuel and purchaed power costs as an element from which the relatively fixed common costs are allocated. I offer clea evidence below tht common costs simply do not var in any relation to changes in fuel and purchased power costs. APART FROM ACCOUNTING AND STATISTICAL DATA, is THRE A COMMON SENSE EXPLANATION AS TO WHY COMMON COSTS SHOULD NOT BE ALLOCATED ON TH BASIS OF FUEL AND PURCHASED POWER COSTS? Yes. As we are all awae, fuel and purchased power prices have risen, fallen, and agai risen by as much as several hundred percent on a year-to-year basis. Ifwe assume; as A vista has done, that common costs are caused by chages in fuel and purchased power costs, then we wil be changing the common cost allocator by as much as several hundred percent year-by-year. Another way of stating the misapplication is that A vista is implying tht its expenditues on offce buildings, fuitue, pars inventories, vehicles, computers, offce supplies, employee pension and benefits, rents and general plant maintenance can be expected to var directly with the recent huge swings, both up and down, in fuel and DIRCT TESTIMONY OF DENNIS E. PESEAU - 36 IPUC Case Nos. A VU-E-041 and A VU-G-1 1 purchaed power prices. (See Exhbit 16, Schedule 2, Pages 10-11 for complete list of 2 common (A&G) cost items.) 3 Q.DOES THIS DISTORT THE COST OF SERVICE RESULTS? 4 A.The distortion is huge, because fuel and purchasd expenses from year to yea comprise 5 the overwhelmng majority of Direct O&M expenses. For example, of the total test year 6 O&M expenses of $97.7 millon (Exhbit 16, Schedule 2, Page 10, Line 369) $66.5 7 millon, or 68 percent of the total is fuel and purchased power expenses. The effect on 8 customers of allocating relatively fixed common costs on volatie fuel and purchased 9 power prices is to cause huge swings in the levels of common costs allocated to each 10 customer class. These swings have nothing to do with the common costs of servng these 11 customer classes. 12 Q.IS THERE AN EASY, COST-BASED FIX TO A VISTA'S VOLATILE AND 13 INACCURATE COMMON COST ALLOCATOR? 14 A.Yes, apar from the inclusion of ful and purchased power expenses, the remaining Direct 15 O&M Expense factor is fairly indicative of, and related to the need to incur, common 16 costs. The easy fix is to simply remove the fuel and purchased power expenses and use 17 the remaining non-fuel and purchased power O&M expenses as one of the four-factors 18 for common cost allocator proposed by A vista. 19 Avista's Histoncal Common Costs are Inversely Related to Fuel 20 and Purchased Power Expenses 21 Q.OTHR THA YOUR COMMON SENSE DISCUSSION, HAVE YOU ATTMPTED 22 TO ESTABLISH EMPIRICALLY THAT AVISTA'S EXPENITURS FOR FUEL 23 AN PURCHASED POWER DO NOT DlREClL Y RELATE TO, OR CAUSE 24 AVISTA'S COMMON COSTS? DIRECT TESTIMONY OF DENNS E. PESEAU - 37 IPUC Case Nos. A VU-E-04-1 and A VU-G-1 1 A. 2 3 4 Q. 5 A. 6 7 8 9 10 11 12 13 Q. 14 15 16 A. 17 18 19 20 21 Q. 22 A. 23 Yes. My Exhbit No. 204 is a graph of the recent history of Avist's anual varations in tota fuel and purchased power expenses comparng them with Avista's actu A&G (common) costs, 1998-2003. WHAT DOES EXHIBIT NO. 204 SHOW? Exhibit No. 204 confrms what we know to be tre - tht Avist's fuel and purchased power costs have vared trmendously on a year-to-year basis since 1998. The exhibit also confrms the point I was making above, that Avista's common (A&G) costs have been virtally const since 1998. Use of the fuel and purchaed power expense component within A vista's Direct O&M factor would therefore generate widely fluctuating allocations of common costs to different customer classes, distortng the intent of a common cost allocator. Statistical Relationship Between O&M and Common Costs WHT STATISTICAL VERIFICATION DO YOU HAVE THAT INDICATES THAT A VISTA'S INCLUSION OF FUEL AND PURCHASED POWER EXPENSES IN ITS COMMON COST ALLOCATOR IS INCORRCT? The use offormal statistcal analysis to prove tht volatile, varable costs for fuel and purchasd power are not correlated with fied common costs may be overkill, but I neverteless offer a statistical regression analysis supportng my arguments. The statistical tests or "hypotheses" I review also indicate tht fuel and purchased power costs should be excluded from the allocator used to allocate common costs. PLEASE EXPLAIN. The regression anysis I performed simply anwers the question of whether Avista's incurrence of common costs is fudamentally related to a definition of O&M expenses DIRCT TESTIONY OF DENNIS E. PESEAU - 38 IPUC Case Nos. A VU-E-04-1 and A VU-G4-1 2 3 4 5 6 7 Q. .8 A. 9 10 11 12 13 14 15 16 17 Q. 18 A. 19 20 21 Q. 22 A. 23 that includes or çloes not include fuel and purchased power expenses. As our goal in the cost of service study is to identify the causative factors of common costs, we searh statistically for the accounts makg up O&M expenses tht do, and those tht do not, cause A vista to incur common costs. Then, in the allocation of common costs to customer classes, we use only those O&M accounts that do relate to, or "cause" common costs. WHT DOES YOUR STATISTICAL REGRESSION ANALYSIS SHOW? The analysis shows that common cost ar much more related to, or "correlated with," O&M expenses that have had fuel and purhased power expenses removed. The regression analysis was conducted for two different equations: 1. Common Costs related to (O&M minus F&PP expenses); and 2. Common Costs related to (O&M with F&PP expenses) where F&PP refers to fuel and purchased power. Exhibit No. 205 sumanzes the results of regressions for these two equations. For completeness, common cost data were developed two ways: first meaured as A&G costs; second, as dollar levels of Avista's genera plant accounts. HOW WERE TH DATA DERIVD? All data were taen from the 2003 FERC Form I s, for A vista and the five other western electrc utities listed in Exhbit No. 205. The other five utilities provide a representational cross section of similarly situated electc utilities. PLEASE SUMMARIZE THE QUANTITATIVE FINDINGS. Regardless of whether A&G expenses or general plant is used as the measure of common cost, the regression results strongly indicate that O&M expenses less fuel and purchased DIRECT TESTIMONY OF DENN E. PESEAU - 39 ¡PUC Case Nos. A VU-E-04-1 and A VU-Gi 1 2 3 4 5 6 Q. 7 A. 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 Q. 23 power expenses is a superior allocator, compared with Avist's proposed change of including fuel and purchased power expenses. This anlysis support the common sense reasoning and graphic evidence presented earlier, and it demonstrates that Avista's proposed change in these proceedings to include fuel and purchased power expenses to allocate common costs should be rejected. HOW SHOULD COMMON COSTS BE ALLOCATED IN THESE PROCEEDINGS? I believe that the Commssion is left with two reasonable alternatives. First the Commssion could adopt in principle Avista's four-factor common cost allocator concept, but simply order the Company to remove fuel and purhased power expenses from the one factor, Direct O&M Expense. In this way, each of the factors in the four-factor method would closely track common costs. I have paricipated in cost of servce stdies in the past where FERC ha similarly removed fuel and purchased power expenses from the Direct O&M Expense accounts. Alternatively, the Commission could order Avista to continue to use the previously approved common cost allocator, where cost were allocated 40% on energy and 60% on cusmer counts. The allocations resulting from the two alternatives are similar in ths case. My Exhbit No. 205 reflects the cost of service results from the four- factor "Direct O&M less F &PP expenses" method. My recommendation to the Commission is to use the four-factor Direct O&M less F&PP expenses method. Avista's Transmission Cost Allocator DOES AVISTA'S COST OF SERVICE STIY CORRCTLY ALLOCATE ITS TRASMISSION COSTS? DIRCT TESTIMONY OF DENNIS E. PESEAU - 40 IPUC Case Nos. A VU-E-04-1 and A VU-G-1 ...... ...... .... 1 A. 2 3 4 5 Q. 6 7 A. 8 9 10 11 Q. 12 A. 13 14 15 16 17 18 19 20 21 22 Transmission costs are incured to meet peak demands, and are therefore appropriately allocated to customer classes on the basis of demand (capacity) allocators. Avista's proposed cost-of-service study allocates a signficant amount of transmission costs, not on demad, but on an energy basis. This is no longer defensible. DID AVIST A'S COST OF SERVICE STIY IN WW-E-98-AA ALLOCATE TRNSMISSION COSTS SIMIARLY ON A DEMA AND ENERGY BASIS? Yes. Unlike the previous issue on the four-factor method, the transmssion allocation issue I raise here clealy would require the Commission to modify its position in the previous rate case, and adopt the same methodology it recently approved in the Idao Power rate case. But I believe the evidence supportng this chage is compellng. PLEASE EXPLAI. My proposal to allocate transmission costs stctly on a demand basis is based on thee distinct propositions: 1. A vista's and virtualy all other transmission systems are planed, sized, and built to meet maximum instataeous, or peak demads. 2. Avista's proposed demand/energy tranmission allocator is inconsistent with, and contrictory to, the same tranmission system rates it has ha approved, and indeed charges, to wholesale customers though its Open Access Transmission Tariff ("OA TI"). 3. The Commission has just weeks ago approved the demand allocator for transmission costs that I propose here in the recently completed Idaho Power general rate case. DIRECT TESTIMONY OF DENNIS E. PESEAU - 41 IPUC Case Nos. A VU-E-1 and A VU-G1 1 Q. 2 3 4 A. 5 6 7 8 9 10 11 12 13 14 15 Q. 16 17 18 19 A. 20 21 22 23 WHAT is TH BASIS FOR YOUR CONCLUSION THAT A VISTA'S TRSMISSION SYSTEM is CONSTRUCTED TO MEET ITS PEAK DEMAN REQUIREMETS? Our firm ha examned system planng methods and models for many years. For generation systems, a hydro-electrc dam being a good example, constction costs can be incured to meet both demand and energy considerations. In the Pacific Nortwest, for example, we know that hydro generation costs are incured or "caused" not only by peak demand requirements, but also by the need to store energy. Generation costs are routinely allocated to both demand and energy. Transmission system, whie they obviously trmit energy, are planed for, and the cost is caused by, the need to meet peak demands. Once the costs are incurred and the facilties constrcted, no additional costs are incurd to transmit energy. Thus, the pnnciple of cost-causation leads us to allocate transmission on the basis of demand (capacity) usage only. HOW is A VISTA'S PROPOSED DEMANDIEERGY TRANSMISSION ALLOCATOR INCONSISTENT WITH TH TRSMISSION COST ALLOCATION AND RESULTING RATES IT HAS IN PLACE FOR WHOLESALE TRANSMISSION USERS? The open access policies implemented by FERC some years ago, as we know, requie Avista and other utilities to fie and maintai OATTs, the rates of which must be based on cost of service. I have reviewed the curent A vista OA TT and determined that the Company allocates its transmission system costs (the same system contaied in its present tranmission cost of service) not on the basis of the demand/energy allocator DIRCT TESTIMONY OF DENNS E. PESEAU - 42 IPUC Case Nos. A VU-E-4-1 and A VU-G-1 1 2 3 4 Q. 5 6 A. 7 8 9 10 Q. 11 12 13 A. 14 15 16 17 18 Q. 19 20 A. 21 22 23 proposed in ths general retal rate case, but rather on the same demand basis that I am proposing here. There is no reasonable justification to have two different sets of transmission costs and rates for the same identical system. HOW DO YOU KNOW THAT THE APPROVED OAIT RATE is BASED ON A DEMAND-ONLY ALLOCATOR? In my Exhibit No. 207 I attch a copy of the relevant pages of Avista's present OA IT. The rates posted there are denved stnctly on a "per kW" or demand basis. This indicates that the OAIT rates and the trmission costs contaned therein are based solely on a demand allocator. DO PROBLEMS ARSE FROM ALLOCATING TH SAM TRASMISSION COSTS OF SERVICE ON TH BASIS OF TWO DIFFERENT ALLOCATORS, AS A VlSTA is PROPOSUNG? Yes, obviously so. First, the demand method is correct and the demand/energy is not. Therefore, one set of rates is correct and the latter is not. Ther is no sound reason why identical retai or wholesale trmission customers should have their respective cost allocations and therefore their rates differ for the same usage. This is disparity is not only ilogical; it is also potentially discriminatory. WHAT TRSMISSION COST ALLOCATION METHOD DID THIS COMMISSION ADOPT IN TH RECENT IDAHO POWER GENRAL RATE CASE NO. IPC-03-13? The Commssion based its rate design on Idaho Power's basic cost of service stdy, which allocated the Company's trsmission costs on the basis of demand only. Idao Power's approved OA IT rates are also based on demand-only transmission cost allocators. DIRCT TESTIONY OF DENNIS E. PESEAU - 43 IPUC Case Nos. A VU-E-04-1 and A VU-G-1 1 Q. 2 3 A. 4 5 6 7 Q. 8 9 10 A. 11 12 13 14 15 16 17 Q. 18 19 A. 20 21 22 23 HAVE YOU PREPARD A COST OF SERVICE STUY THAT INCORPORA'iS THE CHANGES YOU RECOMMND? Yes. Exhbit 206 is a sumar of the results of my cost of service study incorporating the proper 4-factor and transmission capacity allocator. Whle the changes to the allocations to the varous customer classes ar not dramatic, they are signifcat and necessar to propely capture cost of servce. WHAT DOES YOUR COST OF SERVICE STUDY SHOW WITH RESPECT TO TH PRESENT CONTRUTIONS THAT DIFFERE CUSTOMER CLASSES ARE MAKG TOWARD RESPECTIE COSTS OF SERVICE? The swnmar results indicate, consistent with the conclusions of Avist's cost of service study, that residential customers, Schedule 1, and large general service customers, Schedule 25, are receiving substatial subsidies from al remaining customer classes, including Potlatch. Page 1 of Exhbit 206 shows that the residential and generl service customer classes' rates generate rates of retu that are significantly below the system's average rate of retu, thus indicating tht other classes' rates are set too high in order to make up the shortall. HOW SHOULD THE COMMISSION DEAL WITH TH ELIMINATION OF THSE SUBSIDIES? In the recent Idaho Power generl rate case I testified that a huge subsidy, in tht case to the irrgation pwnping class, needed to be systematically and unequivocally reduced to zeo, necessitating a large increase to the irrgators. The same pnnciples apply here, although the levels of subsidies to the residential and genera servce customers are not so large as in the Idaho Power case. In principle, I believe these subsidies should be DIRCT TESIMONY OF DENNIS E. PESEAU - 44 IPUC Case Nos. A VU-E-G4-1 and A VU-G-1 2 3 4 5 6 7 8 9 10 11 12 13 14 Q 15 A. 16 17 18 19 20 21 22 Q. eliminated immediately. However, I am also aware the Commission has expressd concerns about the ''rate shock" that could result from very steep increases for a parcular customer class. Accordigly, I propose in these proceedings tht, if the overl approved increase is ten percent or less, all customer classes should be moved to ful cost of service. If the increase is greater th ten percent, the Commission order should order residential and large genera service rates moved at leas hafway toward rate of retu party, with two anua automatic adjustents thereaer to close the remaining cost of service gap. Under the latter alternative, the other customer classes (Schedules 11-12, Schedules 21- 22, and Potlatch) would continue to pay a subsidy in the near term, but would receive assurances that the remainig subsidy would be eliminated over the next two year. Ths is, I believe, more than fai to the subsidized customer classes. Rate Design Issues DO YOU HAVE ANY COMMENTS ON AVISTA'S RATE DESIGN PROPOSALS? Yes. My first obseration is that Avista's proposal to include Potlatch's Lewiston Facilty ("Facilty") in Tariff Schedule 25 should be rejected. Becaus of the huge disparity in size between the Facilty and the other Schedule 25 customers, it makes no sense to include the Facilty in that schedule. For customers the size of the Facilty, the Commission has always used separate taiffs for each special contrct customer, and it should do so in ths case as well. The Facilty is approximately thre times the size of all the entie Schedule 25 class. IS TH FACILITY IN FACT A SPECIAL CONTRCT CUSTOMER? DIRECT TESTIMONY OF DENNIS E. PESEAU - 45 IPUC Case Nos. A VU-E-4-1 and A VU-G--1 1 A.Yes. The A vista and Potlatch power supply agreement ("Agreement") is a unque 2 contrct tht governs Avist's serice to only one custmer- the Facilty. In that 3 Agreement, the pares agreed to the tempora use of Schedule 25 rates for service to the 4 Facilty, pending the next rate case. But Potlatch did not agree to become a Schedule 25 5 customer. The Facilty has always been a "special contract customet' in the past, and the 6 Agreement clearly contemplates that ths statu will continue in the futue. 7 Q.is IT DIFFICULT TO SEPARTE mE FACILITY'S COST OF SERVICE FROM 8 SCHEDULE 25? 9 A.No. The A vista cost of service study, and my own, already compute all cost of service 10 elements for the Facilty on a std-alone basis, in recogntion of the fact that the Facilty 11 is indeed a customer class unto itself. Given this, the Commssion should require A vist 12 to preserve these cost elements treating the Facilty as the cusomer class tht it is. It 13 makes no sense to subsequently meld the Facilty with the much smaller Schedule 25 14 class. In order to set rates for the Facilty withn the Schedule 25 class, A vista in this 15 case ha to resort to major rate design changes in order to properly assure that Potlatch 16 would not be overcharged. 17 Creating a stand-alone rate schedule for the Facilty will not afect the Facilty's 18 cost of serice or rates. It is simply a preventive measure. The concer is tht in the 19 futue this distinction could be blured in a subsequent study in a maner tht causes the 20 Facilty to pay costs for which it should not be accountable. The distinction between the 21 Facilty and the Schedule 25 customers should be clarfied by placing the Facilty in a 22 separte rate schedule. 23 Q.DOES THS COMPLETE YOUR TESTIONY? DIRCT TESTONY OF DENNIS E. PESEAU - 46 IPUC Case Nos. A VU-E-4-1 and A VU-G1 1 A.Yes, it does. 2 DIRCT TESTIMONY OF DENNIS E. PESEAU - 47 IPUC Case Nos. AVU-E-1 and AVU-G-01 1 2 Q. 3 4 A. 5 6 7 8 9 10 11 12 13 14 15 16 17 Q. 18 19 A. 20 21 22 23 24 25 26 27 Appendi A-Update to Dr. Avera's Analysis WHAT is TH CORRCT RETU ON EQUITY RAGE USING DR. AVERA'S METHODS FOR ESTIMATING EQUITY RETUS? I conclude that consistent application of the discounted cash flow (DCF) and risk premiwn methods used by Dr. Avera reduces his recommendations as follows: Avera EstimatenIROE Method Peseau Update DCF Risk Premiwn I Risk Premiwn II CAPM 10.4% 11.4 10.8 11.9 9.3% 10.8% 9.2% to 10.1% 10.9% _n1 includes flotation costs of 20 basis points. Updates that are consistent with the methods Dr. Avera utilizes do not support his rage of 10.4% to 11.9% and certnly do not support a recommended ROE of 11.5%. See Exhbit No. 211. WHAT GENERAL COMMENTS DO YOU HAVE REGARING TH TESTIMONY AND ANALYSES OFFERED BY DR. AVERA? Dr. Avera offers 70 pages of testimony covering a nwnber oftopics. Twenty-four of these pages cover discussion of flotation costs and the quantitative equity retu methods and estimates commonly considered by this Commission. The rest of the testiony is concerned with general and fudaental economic and finacial topics that are normally and effciently taken into account by investors when bidding on and purchasing common stock and other assets. Financial initutions and investors know the finacial and operational characteristics of Avist every bit as well as Dr. Avera and use ths information to make formal investment decisions. A well-known financial principle is tht investors are not normally, nor do they expect to be, compensated for nonmarket or DffECT TESTIMONY OF DENNIS E. PESEAU - 48 IPUC Case Nos. AVU-E-4-1 and A VU-G-01 1 2 3 4 5 6 Q. 7 A. 8 9 10 11 12 13 14 15 16 17 18 19 Q. 20 21 A. 22 23 company-specific risks that are not systematic. These risks are diversifable and do not, and should not form the basis of rate of retu "adders." The methods of determining cost of equity used by Dr . Avera and others in this case measure retus that are commensurate with similar risk-adjusted investments and should not be adjusted for exogenous risks. PLEASE SUMMARZE DR. AVERA'S ESTIMATES. Dr. Avera presents four quatitative analyses of the cost of equity for a "benchmark" group of western electric utilties from which he derives a 10.2% to 11.7% equity cost range. He presents a discounted cash flow ("DCF") analysis for a benchmark group of electrc utilties in the western U. S., two risk premium approaches, and an estimate based on the capita asset pricing model ("CAPM"). From his DCF analysis, he estimates that a benchmark sample of western electrc utilities requires a return on equity of 10.2% (page 45). Based on two risk premium models, he concludes that the cost of equity for the respective reference samples of electrc utilties is 11.2% (page 49) and 10.6% (page 50). And, from his CAPM approach, he derives a cost of eqty estiate for the western electrc utilties of 11.7% (page 51). Basd on that inormation, and an adder of 20 basis points for flotation costs and additional premium he argues are required for risk specific to Avista he endorses an ROE of i 1.5%. HOW DOES HE REACH TH CONCLUSION TIT AVISTA SHOULD BE AUTHORIED AN EQUITY RETURN IN EXCESS OF 11.5%? Dr. Avera presents lengty discussions of company-specific risks that he contends are faced by A vista and should be recognized in setting the authorized retu. That analysis of unque risks is the basis for his contention that the Company requies an equity retu DIRCT TESTIMONY OF DENNIS E. PESEAU - 49 IPUC Case Nos. A VU-E-04-1 and A VU-G4-1 1 2 3 4 5 Q. 6 A. 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 near the top of his estimate of the equity cost range for other western electric utilties. But as I just explaied, these company specific risks are incorporated into his results, and a subjective adder for such risks is unwaranted. Update to Dr. Avera's DCF Approaches DO YOU HAVE ANY COMMNTS ABOUT HIS DCF ANALYSIS? Yes. Recall that the DCF method under stadard ficial assumptions reduces to the equation: ROE = DilPo + g where ROE =requied equity retur D¡=first penod dividend rate Po =today's stock pnce g = growt rate Dr. Avera's estimate ofa 10.2% retur results from his estimate of the DCF components: 10.2% = 4.2% (yield) + 6.0% (growt) I update the 6.0% growt rate and his dividend yield. The growt rate g is growt that is expected in the future by investors. It is by natue forward looking. But I note that on Dr. Avera's Schedule WEA-2, he used not only the typical benchmark for expected growt, as reported by the investor institutions mES, Value Line, First Call and Multex Investor, but also histoncal rates of earngs growt for both five and ten year past penods: DIRCT TESTIONY OF DENNIS E. PESEAU - 50 IPUC Case Nos. A VU-E-041 and A VU-G-4-1 1 2 3 4 5 6 7 8 9 10 Q. 11 12 13 A. 14 15 16 17 18 19 20 21 22 23 24 25 Dr. Avera's Expected Growt Rates Value First Past PastmESLineCallMultexlOYr.5 Yr. Average Expected Growt Rate 5.1 2.4 5.2 5.4 7.3 8.1 Whle the simple average of these growth rates is 5.6%, Dr. Avera inexplicably uses a 6.0% figure to develop his 10.2% retu. IN YOUR OPINION, IS DR. A VERA'S USE OF TH HISTORICAL GROWT RATES IN HIS AVERAGE AN APPROPRIATE BASIS FOR ESTIMATING THE DCF REQUIRED FUTURE EXPECTED GROWT RATE? No. To the extent that past growt might be of an importce to investors, the anysts' forecasts Dr. Avera reports for mES, Value Line, First Call and Multex have already taen that information into acount. David A. Gordon, Myron 1. Gordon and Lawrence i. Gould, "Choice Among Methods of Estimating Share Yield," Journal of Portfolio Management, pp. 50-55 (Spring i 989), did a study that found analysts' forecasts of growt provide a better explanation of stock prces than thee backward-lookig measures of growt. They explai that their findings make sense because analysts would tae into account past growt as well as any new inormation when they form their forecasts. Roger Mori report the resuts of other empirical studies and concludes analysts' forecasts "are more accurate than forecasts based on historical growt." Regulatory Finance: Utiities Cost of Capital, page 154. My restatement of Dr. Avera's DCF anysis recognizes four of the growt forecasts Dr. Avera relied upon, but gives no weight to the measures of pas growt Dr. Avera reportd. DIRCl TESTIMONY OF DENNIS E. PESEAU - 51 IPUC Case Nos. AVU-E-04-1 and AVU-G...1 1 Q.HOW HAVE YOU MODIFIED DR. AVERA'S DCF EXPECTED GROWT RATE 2 VARILE TO REMOVE TH EFFECTS OF HISTORICAL GROWTH? 3 A.My Exhbit No. 208 shows those resuts. To determe an updated and consistnt 4 estimate for the DCF expected growt rate for each of the utilities in Dr. Avera's sample, S I updated his reported estimates of investor institution projections in Schedule WEA-2 as 6 well as his estate of sustaiable growt in his Schedule WEA-3. Exhibit No. 208 7 shows an average of four growt forecasts; the curent esates reported by IBES, First 8 Call and Reuters (formerly Multex) and the higher of the two forecasts made with Value 9 Line data. Exhbit No. 208 shows that the correct average for the projected or expected 10 growt rate is 5.1 %, close to the bottom of the 5% to 7% range adopted by Dr. Avera. 1l Q.DID YOU UPDATE DR. A VERA'S DIVEND YILDS? 12 A.Yes. I used data published by Value Line, dated June 4,2004, and the method Dr. Avera 13 used to compute dividend yields to make that update. These updated dividend yields ar 14 also reported in Exhbit No. 208. iS Q.BASED ON YOUR UPDATES AN UTILIZA nON OF ONLY THE FORWARD- 16 LOOKIG GROWT RATES REPORTED BY DR. A VERA, WHT is YOUR 17 RESTATEME OF DR. AVERA'S DCF RESULTS? 18 A.Based on his sample and the restatements discussed above, the indicated average cost of 19 equity for the western electric utilities is 9.3% (4.1 % dividend yield and 5.1 % growt, 20 after rounding), 90 basis points less than the 10.2% estimated by Dr. Avera. 21 Q.DO YOU HAVE OTIR CONCERNS WITH DR. AVERA'S DCF ANALYSIS? 22 A.Yes. The DCF method he proposes is incorrect. At page 32, Dr. Avera presents the 23 genera form of the DCF modeL. It clealy shows that expected dividends per shae DIRCT TESTIMONY OF DENNIS E. PESEAU - 52 IPUC Case Nos. AVU-E-4-1 and AVU-G1 2 3 4 5 6 7 8 9 10 11 12 Q. 13 14 A. 15 16 17 18 19 20 Q. 21 A. 22 23 (DPS) are the cash flows that are of interest to investors. He adopts Value Line ~ forecasts of dividends for the next ye~ but ignores Value Line ~ forecasts of dividends for other futue years. His DCF approach is incorrect becaus it does not incorporate all of the inormation on dividend growt that investors consider when they price the shares of common stock in his sample. Had Dr . Avera made his DCF estmates with a multi-stage DCF model that recognized that dividend growt is expected to be less than half as rapid as forecasted earings and sustainable growt for the period 2004 to 2008, the DCF equity cost estimate would be less than 9.3%. But because I limit my testmony to a restatement of the methods Dr. Avera ha relied upon, I have not presented such an analysis. Update to Dr. Avera's Risk Premium Approaches PLEASE DESCRIE THE RISK PREMIUM APPROACH TO ESTIMATIG A UTILITY'S REQUIRED RETUR ON EQUITY. Whereas the DCF method adds estimates of dividend yield to expected growth rate to get equity cost estimates, risk premium methods recognze that over tie common stock is riskier tha most debt securties (bonds) and therefore requires a premium, or adder, over and above the retu on bonds. Ths adder is oftn termed a risk premium. As yields on bonds are generaly directly observable and measurable, equity cost estimates may be derived if reliable risk premiums can be determned. HOW DOES DR. AVERA UTILIZE TH RISK PREMIUM METHOD? Dr. Avera uses a risk premium method based on authorized equity returs, another based on actul or realize return and, finally, the more academically rigorous risk premium method, the Capital Asset Pricing Model (CAPM). DffECT TESTONY OF DENNIS E. PESEAU - 53 IPUC Case Nos. A VU-E-04-1 and A VU-G4-1 1 Q. 2 3 A. 4 5 6 7 8 9 10 11 12 13 14 15 Q. 16 A. 17 18 19 20 21 22 23 WHT EQUITY RETURN DOES DR. AVERA ESTIMATE USING HIS AUTHORIED RETURN RISK PREMIUM METHOD? 1 1.2%. He derives ths by adding a December 2003 bond yield of 6.61 % to a risk premium estimate of 4.58% that is derived in his Schedule WEA-4. Schedule WEA-4 uses regression analysis to attempt to determine the historical relationship between allowed equity retus and bond yields, and the difference between the two, to establish the risk premium. The theory is that if the regression analysis can determine the relationship between the bond yield and the appropriate risk premium, then one can observe today's bond yield, add to it the estiate of risk premium appropriate for the bond yield and add the two to get an equity retur estimate. From Schedule WEA-4, Dr. A vera estimates the relationship as: (ROE - Bond Yield) = .073 + (-.435 x Bond Yield) Whle I have no quael with the basic methodology, Dr. Avera uses interest rates or bond yields that are internally inconsistent in his method. PLEASE EXPLAIN. Dr. Avera uses a low yield bond to compute his historical risk premium. Use of ths 10w bond yield when subtrcted from allowed equity rets, produces an exaggerated or higher risk preum than if a consistent bond rate is used. The bond yield used by Dr. A vera, shown on Schedule WEA-4 is an average of AA, AA, A and BBB rated bonds. Since the highy rated bonds AA, AA and A will have the lowest interest rates, the composite rate Dr. Avera uses is low. Subtracting a low interest rate from an authoried retur yields an arficially high risk premium. Then, on Page 49, Line 10, he adds this high risk premium to the highest bond yield, that of a trple-B bond. Ths mixig of DIRECT TESTIMONY OF DENNIS E. PESEAU - S4 IPUC Case Nos. AVU-E-04-1 and AVU-G-Ø4-1 1 2 3 Q. 4 A. 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Q. 19 20 21 A. 22 23 different bonds for the regression analysis and for computig the equity retu biases upward Dr. Avera's estimate of an equity retur. HAVE YOU AITMPTED TO REMOVE DR. AVERA'S INCONSISTENCY? Yes. An appropriate calculation would use the same measure of bond rating in the regression analysis as in the recommended equity ret. In makg my restatement. I have used A-rated utility bonds to compute the risk premiums. to ru the regressions and to estimate the equity cost. I ,chose the A-rated utilty bond rates because Dr. Avera relies on A-rated bonds in Schedule WEA-5. Also, curent quotations for A-rated utilty bond rates are widely available and published by Value Line every week. I also used trple-B rates, as a second approach in another regression as well, because that is what Dr. Avera uses on his Page 49. The results of the revised analysis ar shown in my Exhibit No. 209. pages 1. and 2. Combinng the revised regression result with a June 4, 2004 Value Line quotation of 6.08% for A-rated utility bond rates gives an indicated cost of equity for the benchmark electrc utilities of 10.8%, 40 bais points lower than Dr. Avera's estimate of 11.2%. Using the triple-B regrssions with the curent trple-B rate of 6.56% reported June 4. 2004 gives a cost of equity estimate of 10.9%. DO YOU HAVE ANY COMMTS ABOUT DR. AVERA'S RISK PREMI APPROACH BASED ON THE REALIZED-RATE-OF-RETU APPROACH THAT HE PRESENTED IN SCHEDULE WEA-5? Yes. First, as he did with his other rik premium approach. Dr. A vera used one type of bond to determine the averge risk premium and then incorrectly added that risk premium to a trple-B public utility bond rate. In ths analysis the risk premium was established as DIRCT TESTIMONY OF DENNIS E. PESEAU - 55 IPUC Case Nos. A VU-E-04-1 and A VU-G-01 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Q. 16 17 A. 18 19 20 21 22 the average difference between anual retus on stocks and A-rated bonds and thus the risk premium will be larger than if the premium were established for trple-B bonds. To make Dr. Avera's approach internly consistent, I added the current A-rated bond to the premium for A-rated bonds. This change alone reduces Dr. A vera's equity cost estimate to 10.1%. See Exhibit No. 210. My other observation is that Dr. Avera's approach assues that investors typically have holding periods of only one year, when investors probably expect to hold shares of utility stocks for longer perods. If investors have very long holding periods, a risk premium based on differences in geometric average retu would be the appropriate risk premium. If, for example, investors have 57-year holding perods, the correct estimate of the risk premium would be 3.11% instead of4.01%. See Exhbit No. 210. I expect that investors typically have holding periods longer than one-year but much shorter than 57 years. In such a case ths appoach would indicate the cost of equity would be between 9.2% and 10.1 % but closer to 10.1 %. DO YOU HAVE ANY COMMENTS ABOUT DR. AVERA'S CAPITAL ASSET PRICING MODEL EQUITY COST ESTIMATE? Yes. Although the CAPM's derivation is steeped in a good deal of financial theory and mathematica determination, the final specifcation, like the DCF method, is fairly straightforward: Equity Cost = Risk Free Rate + Beta x Market Risk Premium There are a number of different ways the CAPM can be implemented and a number of ways that estimates of the risk fre rate and market risk premium can be derived. I limit DIRCT TESTIMONY OF DENNIS E. PESEAU - 56 IPUC Case Nos. A VU-E-4-1 and A VU-Gi 2 3 Q. 4 A. 5 6 7 Q. 8 A. 9 10 Q. 11 A. 12 13 14 15 16 Q. 17 A. 18 19 20 21 22 23 my comments to an update of Dr. Avera's risk free rate and his estimate of the market risk premium (M). I will not contest his meaur of market risk, "beta. n WHT is TH RISK-FREE RATE USED BY DR. AVERA? Dr. Avera uses as a meaure of the risk-free rate the average yield on long-tenn governent bonds. He indicates tht this measure of the risk-fre rate as of December 2003 was 5.2%. WHT is THE RECENT YILD ON LONG-TERM GOVERNT BONDS? The yield reported by Value Line at June 4, 2004 is 5.32%. i use tht value in my updte of Dr. Avera's CAPM estimate. HOW DOES DR. A VERA ESTIMATE THE MARKT RISK PREMIU ("MRP")? Whle I do not agee with his method of estimating the MRP, I use his method here with a simple update. Dr. Avera derives a forecast ofthe tota average market retu for the stock market of 13.7%, then, to estite the market premium he subtracts his risk free rate of 5.2%, which results in an 8.5% MRP. WHAT UPDATE HAVE YOU MADE TO DR. AVERA'S MRP? Whereas the long-term governent bond rate is diectly observable and is set in competitive markets, the other component of the risk premium approach used by Dr. Avera, the projected market retu, is not directly observable or measurable. The projected market retur is simply the opinion about the futue made by different investor institutions and can change frequently. Use of a projected market retu of 13.7%, as of a single point in time, therefore makes the prediction of tota market retur highly varable, as I now show. For reference, the long-tenn average market risk premium durng the DffECT TESTIMONY OF DENNIS E. PESEAU . 57 IPUC Case Nos. A VU-E-04-1 and A VU-Gt 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 Q. 17 18 19 A. 20 21 22 23 period 1926 to 2003 is 7.2%, not the 8.5% used by Dr. Avera. Investors that use CAPM would undoubtedly give weight to that long-term average market risk premium. Dr. Avera's tota market retur estate was made prior to recent stock maket activity that has occurred since December 2003. Investors now understand that a short- term gai as large as 13.7% is no longer realistic. For example, the Value Line forward- lookig tota market retur for the 1700 stocks it follows, as of June 4, 2004, was 12.55%, not the 13.7% used by Dr. Avera. Ths huge potential for varation in these "curnt" MR estimates makes rate of retur settng for regulatory puroses diffcult. Nevertheless, using the updated market retu forecas of 12.55%, the implied MR is 7.23% (12.55% - 5.32%), not the 8.5% used by Dr. Avera. At this time, the indicated "curent" market risk premium and the long-ter averge market risk premium are both 7.2%. If investors consider either indicator of the market risk premium, an update of Dr. Avera's CAPM equity cost estimate is 10.9% as shown below: Equity cost = RF + beta x MR Equity cost = 5.32% + .77 x 7.2% = 10.9% PLEASE SUMMARE YOUR UPDATES AND RESTATEMES OF DR. AVERA'S QUANTITATIVE ESTIMTES OF TH COST OF EQUITY FOR BENCHM ELECTRIC UTITIES. I conclude my strghtforwd updates of Dr. Avera's estimates of the cost of equity do not support a recommended ROE range of 10.4% to 11.9% and certinly do not support an equity retu for A vista of 11.5%. My su Schedule DEP-4 shows that a simple average of the updated equity cost estimates is 140 basis points below the 11.5% ROE that Dr. Avera recommends for Avista. DIRCT TESTIMONY OF DENNIS E. PESEAU - 58 IPUC Case Nos. A VU-E-64-1 and A VU-G.1 Q.DO THE DIRCTIONS IN TRNDS OF FINANCIAL MATS SUPPORT YOUR 2 RECOMMENDATIONS? 3 A.Yes. My Exhbit No. 212 shows monthy interest rate data for lO-year Treasur bonds 4 and for Baa corporate bonds for the period October 2001 though April 2004. as reported 5 by the Federal Reserve. Generally, rates for gOVernent bonds and Baa corporate bonds 6 have decreased by 145 basis points since October 2001. I conclude that, given the drop 7 in capital costs, Avista's cost of equity is well below its 1998 cost. DIRECT TESTIMONY OF DENNI E. PESEAU - 59 IPUC Case Nos. AVU-E-4-1 and AVU-G041 ........................ Conley E. Ward (ISB No. 1683) GIVENS PURSLEY LLP 601 W. Banock Street P.O. Box 2720 Boise,ID 83701-2720 Telephone No. (208) 388-1200 Fax No. (208) 388-1300 cew~givenspursley.com HECEIVEO mFiLED 0 ZLLU11 JUL -9 PH 3: 51 i~~$t\~ ~o ¡..'UBLlC UTlUliES COf1MISSION Attorneys for Potlatch Corporation. S:\CLIENTI3 14\S4\P..u Rett Tesûmony.DOC BEFORE TH IDAHO PUBLIC UTILITIES COMMSSION IN THE MATTER OF THE APPLICATION OF AVISTA CORPORATION FOR THE AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRC AND NATU GAS SERVICE TO ELECTRC AND NATURAL GAS CUSTOMERS IN THE STATE OF IDAHO. Case Nos. AVU-E-04-1 AVU-G-04-1 REBUTTAL TESTIMONY OF DENNS E. PESEAU ON BEHALF OF POTLATCH CORPORATION June 21, 2004 ORIGINAL Q.ARE YOU THE SAME DENNIS PESEAU WHO PREVIOUSLY FILED DIRECT 2 TESTIMONY IN THIS CASE? 3 A.Yes. 4 Q.WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY? 5 B.I have five areas ofbriefrebutt: 6 1.Staff witness Hessing should not have accepted the Deal A excess gas costs 7 because his compellng arguments to disallow Deal B gas costs apply to Deal A as 8 welL. 9 2.Staf witnesses overlooked the signficant change in cost of service methods 10 proposed by A vista witness Knox. 11 3.Staff witnesses Schune's and Hessing's proposal to move varous rate schedules 12 only 20% of the way to cost of service will perpetuate the longstanding subsidies 13 between customer classes. 14 4.Coeur Silver Valley witness Yanel's proposal to directly assign primar costs to 15 Schedule 25 class has merit. 16 5.Stafs proposal to change the method of computing PCA rates should be rejected 17 or modified. 18 Deal A and Deal B Financial Transactions 19 Q.WHAT ARE THE PRIMARY ISSUES YOU ADDRESS IN YOUR REBUTTAL 20 TESTIMONY OF MR. HESSING REGARING DEAL A AND DEAL B? 21 A.In a nutshell, I agree wholehearedly with Mr. Hessing's recommendation to exclude all 22 the excess financial costs of the so-called Deal B. In fact, his approach is quite similar to, 23 and parallels, the rationale I provide for excluding Deal B in my direct testimony. There REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 2 of 16 Case Nos. A VU-E-04-1 and A VU-G-04-1 1 is no need to elaborate on our similar approaches and our identical conclusions with 2 respect to Deal B, other th to point out that our statements of the amounts in dispute 3 differ, primarily because I used system numbers while Mr. Hessing's figures are for the 4 Idaho jursdiction and test year only. 5 My issue with Mr. Hessing's testimony is that the very compellng circumstances and 6 facts that lead Mr. Hessing to appropriately deny A vista recovery of Deal B costs, with 7 one exception, should have also compelled him to recommend disallowance of Deal A 8 costs. My testimony recommends the disallowance of the costs of both Deal A and Deal 9 B. 10 Q.WHT is TH ONE EXCEPTION TO THE SIMILARITY OF CIRCUMSTANCES 11 SURROUNING BOTH DEAL A AND DEAL B? 12 A.The one dissimilar circumstce is that Avista Energy was the counterpary to Deal B. In 13 Deal A the apparent counterparies were Mirant and BP. Thus, the Deal A counterparies 14 that profited so greatly were not par of Avista Corporation's corporate stctue. But in 15 all other respects both Mr. Hessing's and my observations and criticisms regarding the 16 impropriety and imprudence of Deal A and Deal B are the same for both deals. 17 Q.IS THE FACT THAT A VISTA CORPORATION ITSELF DID NOT PROFIT FROM 18 DEAL A SUFFICIENT TO JUSTIFY RECOVERY OF THE DEAL'S EXCESS GAS 19 COSTS IN TH PCA? 20 A.No. Mr. Hessing's other compellng arguments for denying recovery of Deal B costs on 21 the basis of imprudence also hold for Deal A. Both Mr. Hessing's direct testimony and 22 my own explain at lengt the numerous peculiarities and irregularities of both Deal A and 23 Deal B that lead tÇ) the conclusion that each of these deals was imprudent. In fact, the REBUTTAL TESTIMONY OF DENNS E. PESEAU - Page 3 of 16 Case Nos. A VU-E-04-1 and A VU-G-04-1 extended period of 3 Yi years for the Deal A swap actually makes the bet the utilty made 2 3 Q. 4 5 A. 6 ' 7 8 9 Q. 10 11 12 13 A. 14 15 16 17 18 19 20 21 22 on Deal A prices far more speculative and imprudent than Deal B. HOW DOES MR. HESSING EXPLAIN HIS PROPOSAL TO DISALLOW DEAL B BUT ACCEPT DEAL A? On pages 15-16 of his direct testiony, Mr. Hessing offers two reasons for not disallowing Dea A. First, as explained above, the counterparies to Deal A were not A vista affiliates. Second, Mr. Hessing opines that Deal A did not put A vista over "the long limit contained in its Risk Policy." YOU HAVE ALREADY EXPLAIED YOUR POSITION ON DEAL A COUNTERP ARTIES NOT BEING A VISTA AFFILIATES. WHAT is YOUR RESPONSE TO MR. HESSING ALLOWING DEAL A BECAUSE IT WAS STILL UNDER THE "LONG LIMIT?" As I discussed in more detal in my direct testimony, Deal A and Deal B were both financial trades, not physical transactions. In other words, Deal A and Deal B did not purchase any natual gas. On page 5, lines 14-24 of his testimony, Mr. Hessing describes both the physical index-priced gas purchases and the subsequent financial trsactions as if they were all pars of Deal A and Deal B. But the proposed Deal A and Deal B cost adjustments are strctly related only to the financial imprudence of these transactions, and not in any way to the procurement of the physical natual gas. Therefore, i find it irrelevant that the physical purchases were, or were not, over some designated volumetrc or long limit. Neither of the Deal A and Deal B financial trades was prudent on behalf of the utility's custmers for reasons explained in Mr. Hessing's and my testimony. i urge REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 4 of 16 Case Nos. A VU-E-04-1 and A VU-G-04-1 PAGE 5 is CONFIDENTIAL ...........................................................................................................................................-..... ................ ................................................................................. 1 2 3 4 5 Q. 6 7 A. 8 9 10 11 12 13 14 . 15 16 17 18 19 20 21 other reckless and unprecedented featues of both deals that Mr. Hessing and I identitY in our direct testimony, compels the conclusion that both should be excluded from rates on the grounds that their costs were imprudently incurd. Staff Fails to Acknowledge the Importance of Avista's Incorrect 4-Factor Allocator WHAT is YOUR RESPONSE TO STAFF'S ADOPTION OF AVISTA'S COST OF SERVICE METHODOLOGY? Both Mr. Hessing and I testify that Avista's cost of service methodology generally follows that ordered in prior Commission orders. However, I point out that there is a significant change in Avista's newly proposed "4-factor" allocator for common costs. While i indicate tht a 4-factor allocator is not objectionable on its face, the maner in which A vista witness Knox constcts ths allocator is incorrect and unacceptable. My issue here is with Mr. Hessing's characterization of Avista's study as consistent with that used in its last general rate case "with mior modifications" (Hessing, page 4. lines 1-2). What I want to make clear, and demonstrate quantitatively, is that his characterization of "minor modifications" holds only if the newly proposed 4-factor method of allocating common (overhead) costs is corrected as I propose on pages 33-40 of my direct testimony. As I show below, the corrected 4-factor allocator I developed represents a less extreme departure from the previously adopted allocator. In the case of Potlatch's Lewiston Facilty, the prior method and my corrected 4-factor allocator should, and in fact do, produce similar cost allocations, both of which differ significantly from the A vista results. REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 6 of 16 Case Nos. A VU-E-04-1 and A VU-G-04-1 ....... ........j ..................-.............-........................... ......... ..........-........................................... ......... ................. .............................................. ................................................... Q.HOW DO YOU PROPOSE TO DEMONSTRATE THAT THE INCORRCT 2 ALLOCATOR PROPOSED BY A VISTA IS NOT, AS MR. HESSING STATES, A "MINOR MODIFICATION"?3 4 A.Below I list three columns summarizing the rate schedule rates of retu from 1) the 5 "40% energy/60% customer" used and adopted in prior proceedings, 2) Avista's newly 6 proposed but incorrect 4-factor allocator and 3) my corrected Avista's 4-actor allocatorl: Class Schedule 1 General Service Large General Service Schedule 25 Potlatch Lewiston Pumping Lighting AVERAGE 7 Q. 40%/60% Method 1.04% 9.35% 9.26% 2.07% 5.61% 7.79% 6.52% 4.71% Avista 4-Factor 1.97% 9.70% 8.12% 1.17% 5.24% 7.24% 4.55% 4.71 0/0 Potlatch 4-Factor 1.84% 9.52% 8.16% 1.28% 5.60% 7.22% 4.15% 4.71% PLEASE EXPLAIN THIS TABLE. 8 A.My intent here is to show that Avista's incorrect 4-factor allocator is much more than a 9 "minor modification." As I discussed in my direct testimony, Avista's results are skewed 10 by its inappropnate inclusion of variable fuel and purchase power expenses in the 11 definition of O&M. By including these energy costs in an allocator meant to allocate 12 fixed common costs, A vista improperly shifts costs to higher load facor customers. 13 While the percentage shift is relatively small, the effect in absolute terms is not. Avista's 14 flawed cost of service change increases Potlatch Lewiston's cost of service by 15 approximately $1,000,000 per year. A shift of this magnitude in common costs defies 16 common sense. i The Potlatch-calculated retu differ from those in my direct testimony because, in order to make accurate comparisons, I do not here change the transmission allocator, as I recommend in my direct testimony. REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 7 of 16 Case Nos. A VU-E-04-1 and A VU-G-04-1 1 2 3 4 5 6 7 Q. 8 9 A. 10 11 12 Q. 13 14 A. 15 16 17 18 19 20 21 22 Q. Correcting Avista's mistaen inclusion of fuel and purchased power expenses, as I show in the colum headed "Potlatch 4-Factor," produces final allocations that are less prejudicial to high load factor customers and more consistent with prior orders than Avista's approach. My rebutt Exhibit 213 sumarzes the derivation of the Potlatch 4- Factor method. The other colwns are developed from Avista Exhbit 16, Schedules 2 and 3. HOW DO YOU RECOMMND THAT THE COMMISSION RESOLVE THESE DISPARATE COST OF SERVICE RESULTS? I recommend that the Commission either stick with its previously adopted "40%/60%" method, or adopt the corrected 4- factor method that I propose. Staff's Proposed 20%, Movement to Cost of Service is Inadequate WHT IS TH ISSUE WITH RESPECT TO STAFF'S PROPOSAL TO MOVE EACH RATE SCHEDULE 20% TOWAR COST OF SERVICE? Both Staff witnesses Messrs. Hessing and Schune proposed to limit the movement of each customer class's rates to 20% of the discrepancy with cost of service, with the remaining revenue requirement deficiency being made up by spreading the deficiency on the basis of an equal percentage to each rate class. iMy issue here is that the Staff proposal once again blunts any meaningful movement to cost of servce, thereby continuing indefinitely the longstanding inter-class rate subsidies. The concurrent PCA reduction makes this an ideal time to finally make some progress toward rate party. PLEASE EXPLAIN. REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 8 of16 Case Nos. AVU-E-04-1 and AVU-G-04-1 1 A.Staff justifies its proposal to make minimal progress toward cost of service on the basis 2 of avoiding rate shock. The unortate consequence of limiting rate increases of 3 customer classes curently being subsidized is that it generates a corresponding rate shock 4 to rate classes that are already paying well in excess of cost of service (Potlatch's 5 Lewiston Facilty). For example, staff proposes an overall average rate increase of 6 15.8%. As my char on page 7 of ths testimony points out, the residential class's rates 7 currently generate roughly 20% to 40% of the average rate of retu no matter which 8 cost of service method is adopted. Yet staff proposes to limit the increase to the 9 residential class to 18.8%. On the other hand, Potlatch's current rates generate returns 10 well in excess of the system average return, yet Staffs proposal results in a 14.9% rate 11 increase for Potlatch. Stated another way, depending on the cost of service methodology 12 chosen, Potlatch is generating a rate of retu that is approximately 3 to 5 times that of i 3 the residential class, but the Staf proposes only a 3.9% difference in the percentage rate 14 increase assigned to the two classes. I respectflly submit this result is neither just nor 15 reasonable. 16 Q.HOW DOES STAFF'S RECOMMENDATION IN THIS CASE SQUARE WITH ITS 17 RECOMMENDATIONS IN THE PAST? 18 A.As I understad it, in the previous A vista general rate increase Staff proposed thee cost i 9 of service options-to move rates one-third, one-half, or entirely to respective costs of 20 service. The Commission instead selected 20% as the overall cap on the movement to 21 cost of service. 22 Q.DID THAT INITIATIVE IN FACT RESULT IN A PARTIAL CORRCTION OF 23 RELATIVE RATE OF RETU DISPARTY? REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 9 of 16 Case Nos. A VU-E-04-1 and A VU-G-04-1 1 A.Unfortnately, no. In fact the inter-class subsidy of the residential class has increased, 2 rather than decreased, since the last Avista rate case. Under these circumstances, the rate 3 shock argument is wearng very thin. There has been no progress toward the elimination 4 of this subsidy for roughy five years, and I suspect Stafs proposal, if adopted, will be 5 revealed to produce little or no progress when the next A vista rate case rolls around. I 6 fuly realize ths is a tough issue for the Commission, but the indefinite continuation of a 7 subsidy of ths magnitude is simply intolerable. It is bad economics and bad policy and, 8 at best, it only postpones the day of reckonig when the residential class will ultimately 9 have to pay its full cost of servce, or something very close to it. At that point, the rate 10 shock will be far worse than it would be in this case. 11 Q.AR THERE CIRCUMSTANCES IN TH PRESENT CASE THAT WOULD SOFTE 12 TH RATE IMPACT OF MOVING MORE BOLDLY TOWARD COST OF SERVICE? 13 A.Yes, the proposed PCA reduction provides an offset to any rate increase the Commission 14 ultimately approves. For example, if the Commission adopts the Stafs proposed 15.8% 15 general rate increase, the net increase for the Idaho jursdiction afer the PCA adjustment 16 is only 2.4%. Under Staffs 20% proposal, the net increase in residential rates would be 17 only 5.1 % in ths scenao. There is clearly room to make a more meanngful move than 18 this to equal class rates of retur without causing rate shock. 19 Q.WHAT DO YOU RECOMMEND THAT TH COMMISSION ADOPT IN TERMS OF 20 MOVEMENT TOWARD COST OF SERVICE? 21 A.I recommend that the Commission do two things. First, it should order that customer 22 class rates move 50% toward cost of service in this case. Second, the Commission REBUTTAL TESTIMONY OF DENNS E. PESEAU - Page 10 of 16 Case Nos. A VU-E-04-1 and A VU-G-04-1 1 2 3 4 Q. 5 6 7 A. 8 9 10 11 12 13 14 15 16 Q. 17 A. 18 19 20 21 22 23 should express the intent that in subsequent cases, or within 2 year if no general rate case is fied, rates wil be moved an additional 50% toward cost of service. Coeur Silver Valley's Direct Assignment of Primary Distribution Costs I NOTICE YOU DID NOT DISCUSS SCHEDULE 25, THE OTHER CUSTOMER CLASS THAT APPEARS TO BE REA VIL Y SUBSIDIZED, IN THE PRECEEDING SECTION OF YOUR TESTIMONY. WHY is THAT? Afer reading Mr. Anthony Yanel's direct testimony on behalf of Coeur Silver Valley, I am convinced that all of the cost of servce studies in this case, including my own, significantly overstate Schedule 25' s cost of service. Mr. Yankel points out that it is possible and practical to directly identify all those A vista primary facilties necessar to serve all Schedule 25 customers from the Company's accounting records. Since ths is possible, Mr. Yanel argues that it is always more accurate to directly assign those facilties' costs to Schedule 25 customers, rather than average these customer-specific costs into all other residential and smaller general service customers and then allocate them on a less accurate basis. WHAT IS YOUR POSITION WITH RESPECT TO THIS ISSUE? While I have not fully reviewed Mr. Yanel's analysis, I can state that his position that directly assigned costs are more accurate than those derived by a computed allocation is correct. The reason tht directly assigned costs better reflect cost of service is rather straightforward. If I can directly identify those investments made specifically to serve a customer, I can clearly trace both the cause and the costs of those investments to that customer. Mr. Yanel has identified the direct costs of primary distribution facilities REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 11 oft6 Case Nos. A VU-E-04- i and A VU-G-04-1 used to serve Schedule 25 customers and, as I understand it, proposes to directly assign 2 these identifiable costs to the Schedule 25 class. I certainly agree in principle that this 3 direct assignment is preferable to an indirect cost allocation. 4 According to Mr. Yanel's calculations, this direct assignment of primar distibution 5 facilties signficantly reduces the purrted subsidy of Schedule 25 customers. I have 6 not attempted to verify his calculations. But as I have just noted, Mr. Yanel's 7 adjustment is correct in principle, and uness someone can demonstrte that it has been 8 improperly implemented or calculated, his ultimate conclusion-that Schedule 25's cost 9 of service is overstated-is correct as well. 10 Staffs Proposal to Change Basis for Computing peA Rates 1 I Q.DOES STAFF PROPOSE TO CHANGE THE BASIS UPON WHICH PCA RATES 12 ARE COMPUTED? 13 A.Yes, on pages 22-24 of his testimony, Mr. Hessing proposes that the Commission change 14 from the curent method of spreading peA account balances to customer class rates on an 15 "equa percentage" basis to a method of spreading balances on an equal cents per kwh 16 basis. 17 Q.WHT IS YOUR POSITION ON THIS ISSUE? 18 A.I oppose the proposal on both theoretical and practical grounds. First, I have always 19 argued that power supply costs are not 100% energy or kwh-based and should not, 20 therefore, be spread on an energy-only basis. There is both a fixed or capacity 21 component and a seasonally-differentiated cost component to power supply costs that 22 makes spreading balances on a flat, equal kwh basis inaccurate. Recovering power REBUTAL TESTIMONY OF DENNIS E. PESEAU - Page 12 ofl6 Case Nos. AVU-E-04-J and A VU-G-04-1 2 3 Q. 4 A. 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Q. 22 A. 23 supply adjustments on a per kwh basis is inconsistent with the way we establish base rates. and should be rejected as a matter of principle. WHAT IS YOUR PRACTICAL OBJECTION TO THE PROPOSAL? In theory. whether PCA changes are recovered through percentage changes or energy rate adjustments should be a matter of indifference to ratepayers. Ifbase rates are properly set, a customer who pays more under an energy only recovery of a surcharge wil also receive a proportionately larger benefit from any PCA "rebate," Over the long haul, each customer's tota PCA exposure should be the same under either recovery method. But as a practical matter, high load factor customers such as Potlatch who compete in national or global markets are not really indifferent. Switching to a per kwh recovery method will make these customers' rates much more volatile, because the surcharges and rebates will both be greater than under the curent system. In short. their high rates will be higher and their low rates 10wer under Mr. Hessing's proposal. This is a concern for Potlatch and other industral customers because it makes business planing and management more diffcult. Furthermore, rate increases can cause disruptions and losses that cannot be recovered by corresponding decreases in subsequent years. To cite but one example, a PCA rate increase can potentially shut an industrial customer off from some markets or. in an extreme case. render production uneconomic in all markets. Losses like these are not likely to be adequately compensated by benefits from PCA rebates in good year. ARE THERE AN OTHER PRACTICAL PROBLEMS WITH STAFF'S PROPOSAL? Yes. On page 23, line7 to page 24, line 2, Mr. Hessing carefully explains that, due to the fact that there are curently positive balances in the PCA accounts, and these accounts REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 13 of 16 Case Nos. A VU-E-04- i and A VU-G-04- i 2 3 4 5 6 7 8 Q. 9 A. 10 11 12 13 14 15 16 17 18 19 Q. 20 A. were collected on the present equal percentage basis, it would be very unfair to high load factor customers to now change and attempt to recover these balances on a new, energy only basis. He proposes that any change approved in the PCA methodology not be implemented until the present deferral balances are cleard. I simply want to underscore that this mixing of methods to accumulate and then to recover such balances is potentially highly prejudicial to high 10ad factor customers unless it is implemented when balances are essentially zero. DO YOU HAVE A SECOND RECOMMENDATION REGARING THIS ISSUE? Yes. If the Commission decides to make the change Mr. Hessing recommends in the name of consistency, it should take the proposal to its logical conclusion. If the Commission really believes tht power supply adjustments are incured on a "per kwh" basis, the "cents per kwh" recovery should be "seasonalizd" on a monthly or quarterly basis in a maner similar to avoided cost rates. Doing so would allow PCA rates, like other cost components, to track the actual changes in power costs as they var overthe year. It is an easy matter to calculate the actual monthly kwh rate that cause the PCA deferral balances to change, and from this information determine the basis for adjusting the PCA rate seasonally. All the benefits of cost-causation and price signal considerations that apply to base customer rates would then apply to PCA rates. DOES THIS CONCLUDE YOUR TESTIMONY? Yes. REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 14 of 16 Case Nos. A VU-E-04-1 and A VU-G-04-1 CERTIFICATE OF SERVICE I HEREBY CERTIFY that on this 9th day of July 2004, I caused to be served a true and correct copy of the foregoing document by the method indicated below, and addressed to the following: Jean Jewell Idaho Public Utilties Commission 472 W. Washington Street P.O. Box 83720 Boise, ID 83720-0074 ( ) U.S. Mail ( JJ Hand Delivered ( 1 Overnight Mail ( 1 Facsimile Scott Woodbur Lisa Nordstrom Idaho Public Utilities Commission 472 W. Washington Street P.O. Box 83720 Boise,ID 83720-0074 swoodbu($puc.state.id. us Inordst($puc.state.id.us ( ) U.S. Mail ( ./ Hand Delivered ( 1 Overnght Mail ( ) Facsimile ( 1 E-Mail David J. Meyer Senior Vice President and General Counsel A vista Corporation P.O. Box 3727 1411 E. Mission Ave., MSC-13 Spokane, WA 99220-3727 david.meyer($avistacorp.com ( 1 U.S. Mail ( 1 Hand Delivered ( J1 Overnght Mail ( 1 Facsimile ( 1 E-Mail Kelly Norwood Vice President, State and Federal Regulation A vista Utilties P.O. Box 3727 1411 E. Mission Ave., MSC-7 Spokane, W A 99220-3727 kelIy.norwood($avìstacorp.com ( ) U.S. Mail ( 1 Hand Delivered (/1 Overnight Mail ( 1 Facsimile ( 1 E-Mail Dennis E. Peseau, Ph.D. Utilty Resources, Inc. 1500 Liberty Street SE, Ste. 250 Salem, OR 97302 dpeseau($excite.com ( ./ U.S. Mail ( 1 Hand Delivered ( ) Overnight Mail ( ) Facsimile ( J E-Mail REBUTTAL TESTIMONY OF DENNS E. PESEAU - Page 15 of16 Case Nos. A VU-E-04-1 and A VU-G-04-1 '" Charles L.A. Cox EVANS, KEANE 111 Main Street P.O. Box 659 Kellogg,ID 83837 ccox~usamedia.tv ( ) U.S. Mail ( J Hand Delivered ( J) Overnight Mail ( ) Facsimile ( J E-Mail Anthony J. Yanel 29814 Lake Road Bay Vilage, OH 44140 ( J U.S. Mail (JJ Hand Delivered ( J Overnight Mail ( J Facsimile ( J E-Mail ( ) U.S. Mail ( ) Hand Delivered ( J) Overnight Mail ( ) Facsimile ( ) E-Mail J U.S. Mail ( ) Hand Delivered ( Jj Overnght Mail ( J Facsimile ( ) E-Mail Brad M. Purdy Attorney at Law 2019 N. 17th Street Boise, ID 83702 bmpurdy~otmail.com Michael Kar 147 Appaloosa Lane Bellingham, W A 98229 michael~awish.net REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 16 of16 Case Nos. AVU-E-04-1 and AVU-G-04-1 ..r 0- .. Edwrd Evett Hale (1929.1993) Ste Lane J. Step Peek Kaen D. Deison R. Crag Howrd Stehen V. Novaek Riclird 1- E1moie Ricli Benntt Alex J. P1anga Kñtin B. McMillan Jams 1- Kelly Kelly Testolin N. Patrck flanag Mattew E. Wooad Michelle D. Mullin Roge W. Jepon Lancc C. EarlJem)'J.Norl Davi A, Garcia Pr D. Gibs lJ Elissa f. Cadish Timotly A. Lukas fnerk J. Schmdt James New David G. LCtlnd Julia S. Gold Torr R. Someri Patrck J. Reily Sctt D. Flemng Jerr M. Snyd Brent C. Eckersley Frerick R. Batther PalTcia C. llalstr-4d Matllew J. Kreutz Maiicw B, Hippler Brad M. Jolion Bry K. KinlinlOlo Douglas C, P10we lusin C, Jones Alexis G. Michaud Thomas R. Ryan Dor V. OjiJillva OfCOUlI...el RoyFanw Pauline Ng Lee Andw Pearl e HALE e LANE ~~~;:: r:~! ".' ~ :~; ~ U~: L ¡ I~ !j": ¡:.; .; . '. . C f : ~;4. .' . l. ,- :r.~.~l. ....~ I''.If '.J ATTORNEYS AT LAW m East WiUia Strt I Suite 200 I ClIß City. Nevda 89701 Telephone (775) 684.60 1 Facsimile (775) 684-01 Website: hit://www.halelane.com 04 OCT 28 Fri 3: 2 U October 28, 2004 Ms. Crystal Jackson Secreta Public Utilities Commission of Nevada 1150 Wiliam Street Caron City, NY 89701 Dear Ms. Jackson: Please accept for filing an original and nine copies of the prefied direct testimony of Dr. Dennis E. Peseau on behalf of the Souther Nevada Water Authority in Docket No. 04-8022. fiing. Please call Fred Schmidt at 684-6008 if you have any questions regarding this Sincerly, - HALE LANE PEEK DENNISON AND HOWARD RENO OFFICE: S441 Kietz Lane I Secnd Floor I Re. Nevda 89511 IPhone (775) 327.3000 I Fac.imile (775) 786.6179LAS VEGAS OFFICE: 2300 Wesi Sahara Avenue I Eigth Floor I Box 8 I Las Vegas. Nevad 891021 l1one (702) 222-2500 I Facsimile (702) 365.6940 C:\ WINNProfiesltemmolCover i.rPUCPleading.do ~ i: \ ..e - ,- ..... k. t. . ~. ~" p i.; ~~: :... j' ,;.-...-cr l . r..::. . ~':. f - r ... : 04 OCT 28 PH ": 'j 0 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA . .J t., Docket No. 04-8022 Direct Testimony of Dennis E. Peseau on behalf of Southern Nevada Water Authority 1 Q.PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 2 A.My name is Dennis E. Paseau. My business address is Suite 250, 1500 3 Liberty Street, S.E., Salem, Oregon 97302. 4 5 Q.BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED? 6 A.I am President of Utility Resources, Inc. My firm consults on a number of 7 economic, financial and engineenng matters for various private and public 8 entities. 9 10 Q.ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? 11 A.I am testifying on behalf of the Southern Nevada Water Authority (SNWA). 12 1 of 12 1 Q. 2 3 A. 4 5 Q. 6 7 A. 8 9 10 11 12 13 14 15 16 17 18 19 Q. 20 A. 21 22 23 24 e - DOES ATTACHMENT 1 ACCURATELY DeSCRIBE YOUR BACKGROUND AND EXPERIENCE? Yes. WHAT IS THE PURPOSe" OF YOUR TESTIMONY IN THESE PROCEEDINGS? The primary purposes for the SNWA involvement in this case are to re-affrm its support for Nevada Power's request to have the Commission approve the HAM 500 kV component of the Centennial Project; to confirm with Nevada Power that the significant transmission needs of the Colorado River Commission (CRC) and the SNWA are in no way compromised by any Company request made in its filing; and to propose that a mutually beneficial joint ownership between Nevada Power and the SNWA of the HAM 500 kV project be considered and Nevada Power be ordered to report back to the Commission the results of discussions with SNWA to consider such a joint ownership option. Ms. Gail Bates describes in more detail the second issue of confirming levels and reliability of CRC/SNWA needs. WHAT CONCLUSIONS HAVE YOU REACHED? I conclude that: 1. Nevada Power's technical studies in this case confirm the economic and engineering superiority ofthe HAM 500 kv project over altematives. However, there are important unresolved 2 of 12 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 APPROVE THE HAM 500 KV PROJECT e e questions regarding the amount of the line that wil be subscnbed. The SNWA therefore conditions its support for the HAM project on the successful discussion on joint ownership Idiscuss below. ' 2.The Commission should require in these proceedings that Nevada Power commit to providing to the CRC/SNWA all contractual and generally åccepted levels of transmission service necessary to protect the integrity of the Southern Nevada water system and represent that the proposed removal of the previously approved McCullough 500/250 kV transformer and the Clark Substation from the HAM 500 kV project would not affect service to CRC/SNWA. 3.The Commission should encourage Nevada Power to immediately investigate the feasibilty of and discuss with the CRC/SNWA the joint development and ownership of the HAM 500 kV project to identify the potential mutual benefits for Nevada Power shareholders, ratepayers and SNWA and water purveyor customers summanzed below. The Commission should order Nevada Power to report back to the Commission within 90 days the results of such discussions. I believe this to be a "win-win" opportunity for all parties. 4.The SNWA does not oppose Nevada Power's request to keep the $15.56 millon in investment reduction due to cancellation of the McCullough transformer component of the HAM project by placing this sum into the contingency fund, but requests that this sizeable sum be sep~rately earmarked as a budget line item, to be used only for newly identified facilties, not merely cost overrns on existing planned facilities. 34 35 Q.WHAT IS THE ISSUE WITH RESPECT TO COMMISSION APPROVAL OF 36 THE PROPOSED HAM 500 KV PROJECT? 3 of 12 1 A. 2 3 4 5 Q. 6 A. 7 8 9 10 11 12 13 14 15 16 Q. 17 18 19 A. 20 21 22 23 e e The Action Plan contained in the Company's proposed Third Amendment Filng (Pages 2-3) requests among other things that the Commission reaffrm its approval of the HAM 500 kV project. WHAT IS THE SNWA'S POSITION ON THIS REQUEST? The SNWA considers this HAM 500 kV component of the overall Centennial Project to be extremely important for the long-term economics and reliability of Nevada Power's electric system. The HAM 500 kV project is an important enhancement to southern Nevada's transmission network and is an ideal facilty to integrate future facilities needed by SNWA to power the existing and planned water system infrastructure. The HAM 500 kV line is considered so important that the SNWA requests that it be allowed to assist in its financing, and development and ownership with Nevada Power, as I explain below. HAVE YOU REVIEWED THE TRASMISSION ALTERNATIVES TO THE HAM 500 KV PROJECT STUDIED BY NEVADA POWER IN ITS THIRD AMENDMENT FILING? Yes. On Pages 6-12 of the direct testimony of Nevada Power witness Larr Luna, and Pages 8-11 of the Third Amendment, the Company discuses the numerous advantages of the HAM 500 kV project over five alternative transmission projects. While I am not a transmission engineer, the clear findings that the HAM 500 kV project is cost competitive, has greater capacity 4 of 12 . .e e 1 2 3 4 5 6 7 8 Q. 9 10 11 A. 12 13 14 Q, 15 A. 16 17 18 19 20 21 22 23 e e Commission's affrmative role in bringing about the recent highly successful sale of power from SNWA's Silverhawk combined cycle plant to Nevada Power as an example of benefits which can be derived with Commission ordered encouragement. The expected outcome of joint ownership of the HAM 500 kV project has even greater benefits to Nevada Power's customers and shareholders, as well as SNWA's, and its member agencies' customers. WHY SHOULD THE COMMISSION REQUIRE THAT A STUDY OF THE BENEFITS OF JOINT OWNERSHIP OF THE HAM 500 KV PROJECT BETWEEN NEVADA POWER AND THE SNWA BE UNDERTAKEN? The prospect of such joint ownership is, in my opinion. clearly a "win-win" sitation, for at least the economic and planning reasons I list below. WHY IS SNWA SEEKING JOINT OWNERSHIP? The SNWA is unique among other parties or customers that either "buy fmmii or "sell into" Nevada Power's system. The SNWA is neither a usual customer of nor usual generator of electricity. The SNWA certainly has, and distributes to, large loads in the Nevada Power system. But the SNWA also has a 125 MW interest in the Silverhawk generating plant and the eRe, largely on the SNWA's behalf, owns the extensive River Mountains transmission facilities located in Nevada Power's service territory. The large and regionally disparate loads served by the SNWA and the necessity of moving power in different directions depending. on Silverhawk and other power source 6 of 12 1 2 3 4 5 6 7 8 Q. 9 10 A. 11 12 13 14 15 16 Q. 17 18 A. 19 20 21 22 23 e e availabilty make partial ownership of the HAM 500 kV project by SNWA a significant opportunity upon which to build up its water system infrastructure in coming years. Simplifing somewhat, the SNWA must, in order to meet the growth in demand for water that it faces, both develop water sources distant to the Las Vegas Valley and be in a position to obtain and distribute electric power to its new water sources in order to pump such supplies to market. WHAT INCREASES IN SNWA ELECTRIC LOADS ARE ANTICIPATED TO SERVE THESE DEVELOPMENTS? While the estimates are preliminary and subject to change, the electnc power eventually expected to be required for new water resource development is in excess of 150 MW of new load in addition to load growth associated with use of the existing water system. A 10% ownership of the HAM 500 kv project would well serve these SNWA pumping requirements. WHAT POSITIVE FINANCIAL BENEFITS DO YOU FORESEE FROM JOINT OWNERSHIP OF THE HAM 500 KV LINE? Due to the present excellent credit standing of the SNWA, its abilty to finance 100% with low cost debt and the present huge capital expenditure budget of Nevada Power, I expect a number of positive financial outcomes to develop: · The financial community and leading credit rating agencies wil perceive this joint ownership as a win-win for investors since it 7 of 12 e e 1 reduces near~term huge capital requirements, improving times 2 interest coverage ratios, liquidity and lowers debt costs. 3 4 · The SNWA's wilingness to discuss means to better integrate 5 the existing CRC/SNWA and Nevada Power transmission 6 systems provides opportunities for additional import capabilty, 7 system reliabilty as additional interconnection to CRC and 8 SNWA's existing transmission is developed. 9 10 · Opportunities to study the potential for the SNWA to finance 11 additional ownership portions of the HAM 500 kV line and 12 transfer benefits "at cost" to Nevada Power could greatly benefit 13 . both investors and ratepayers. 14 15 I offer the above not as an exhaustive list of benefits, but as a few examples of 16 many possible mutual benefits to the parties from sitting down and 17 constructively studying these opportunities. 18 19 Q. WHAT FRACTION OF NEVADA POWER'S TOTAL CAPITAL 20 EXPENDITURES BUDGET WOULD A PROPOSED 10% JOINT 21 OWNERSHIP BY SNWA COMPRISE? 22 A. The relief to Nevada Power's shareholders and customers of the reduction 23 in the Company's near-term capital budget is modest. For example, at a 8 of 12 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Q. 20 21 22 A. 23 e e budget of approximately $100 milion for the completion of the HAM 500 kV project, a 10% joint ownership by the SNWA reduces the near-term budget by $ 10 millon. This amount is, of course, a smaller percentage of Nevada Powets overall capital budget of nearly $ 300 milion per year. But the absolute percentage relief in Nevada Powets capital budget is not the prime consideration here. The announcement effect to investors and credit rating agencies that Nevada Power, its regulators and its customers are encouraging ways to stem the trend in excessively leveraged investment requirements wil improve the Company's investment standing. To the extent that this joint venture opens Nevada Power to additional investment opportunities to invest in interconnections and infrastructure not otherwise available, investors wil understand that this joint venture does not deny present investment opportunities, but rather shifts them into near-term future opportunities when Nevada Power is in an even better financial condition to invest in such assets. IS THE SNWA INDICATING A WILLINGNESS TO COOPERATE TO PURSUE PROJECTS OF USE TO NEVADA POWER AS WELL? Yes, and while I am not providing a list of specific items, certainly a study of interconnection possibilities between Nevada Power and the CRC/SNWA gof 12 1 2 3 4 Q. 5 6 A. 7 8 9 10 11 12 13 Q. 14 15 A. 16 17 18 19 20 21 22 e e would identify such details. There are apparently very significant joint projects that deserve further study to determine whether they can be undertaken . IS JOINT OR MULTIPLE OWNERSHIP OF TRANSMISSION FACILITIES RARE? No. Throughout the United States, multiple ownership of high voltage transmission lines is common. For example, the huge AC and DC transmission lines connecting the Pacific Northwest with Northern and Southern California, having a capacity of several thousand megawatts, are owned by multiple public and private entities which work together to optimize the physical and ecnomic operation of the transmission system. IS PARTIAL OWNERSHIP OF THE HAM 500 kV PROJECT AN UNUSUAL UNDERTAKING FOR AN ENTITY LIKE THE SNWA? No, not at all. As I have stated, the SNWA,does not fit the simple profile of an energy consumer. The SNWA is faced with the tasks of enhancing and developing new souræs of water supplies to Southern Nevada. It is unique among other entities and customers in this regard. Joint ownership now of the HAM 500 kV project would greatly reduce the costs and administrative burdens to the SNWA and Nevada Power in numerous OA TT and other filings before FERC and this Commission. 10 of 12 1 Q. 2 3 A. 4 5 6 7 8 9 Q. 10 11 12 A. 13 14 15 16 17 18 19 20 Q. 21 22 A. 23 e e WHAT SPECIFIC ACTIONS DO YOU REQUEST OF THE COMMISSION WITH RESPECT TO THE HAM PROJECT IN THESE PROCEEDINGS? SNWA requests that the Commission encourage Nevada Power to meet with SNWA to discuss the possibilty of joint ownership of the HAM 500 kV project and order Nevada Power to report back to the Commission the results of such discussions within 90 days of the date of the Order of the Commission in this docket. WHAT IS THE ISSUE WITH RESPECT TO NEVADA POWER'S REQUEST TO KEEP THE $15.56 MILLION IN BUDGET FOR THE CANCELLED MCCULLOUGH TRASFORMER? On page 3, lines 9.26 of his testimony, Nevada Power witness Mr. Luna requests that the Company be allowed to cancel the addition of a $15.56 transformer that was previously seoped and budgeted for the HAM 500 kV project. But, rather than reduce the previous budget by the amount of $15.56 millon, he instead requests that this amount simply be added to the Centennial Project's Risk and Contingency budget. The overall budget therefore remains unchanged. WHAT IS YOUR RECOMMENDATION TO THIS $15.56 MILLION REQUEST? The SNWA does not oppose keeping these funds available, but requests that this sizeable sum be separately earmarked as a budget line item, to be used 11 of 12 1 2 3 4 Q. 5 A. 6 e e only for newly identifed facilities, not merely cost overrns on existing planned facilties. DOES THIS CONCLUDE YOUR TESTIMONY? Yes. 12 of 12 e e AFFIRTION I, Denns E. Peseau, pursuant to NAC 703.710 hereby affir that the foregoing preare testimony was prepared by me or under my direction and is correct to the best of my knowledge. 1L,~Dennis E. Peseau Dated:10-28-01 e e ATTACHMENT 1 e Achment1 Page 1 of3 STATEMENT OF OCCUPATIONAL AND EDUCATIONAL HISTORY AND QUALIFICATIONS DENNIS E. PESEAU Dr. Peseau has conducted economic and financial studies for regulated industries for the past twenty-eight years. In 1972, he was employed by Southern California Edison Company as Associate Economic Analyst. and later as Economic Analyst. His responsibilties included review of financial testimony, incremental cost studies, rate design, econometncestimation of demand elasticities and various areas in the field of energy and economic growt. Also, he was asked by Edison Electrical Institute to study and evaluate several prominent energy moels as part of the Ad Hoc Committee on Economic Growt and Energy Pricing. From 1974 to 1978, Dr. Peseau was employed by the Public Utilty Commissioner of Oregon as Senior Economist. There he conducted a number of economic and financial studies and prepared testimony pertining to public utilities. In 1978 Dr. Peseau established the Northwest offce of Zinder Companies, Inc. He has since submited testimony on economic and financial matters before state regulatory commissions in Alaska, California, Idaho, Maryand, Minnesota, Montana, Nevada, Washington, Wyoming, the Distnct of Columbia, the Bonnevile Power Administration and the Public Utilites Board of Albert on over one e ~chment1 FJge 20f3 hundred ocsions. He has conducted marginal cost and rate design studies and prepared testimony on these matters in Alaska, Califrnia, Idaho, Maryand, Minnesota, Nevada, Oregon, Washington and in the District of Columbia. He has also conducted cost and rate studies regarding PURPA issues in the states of Alaska, California, Idaho, Montana, Nevada, New York, Washington, and Washington, D.C. Dr. Peseau holds the B.A., M.A. and Ph.D. degrees in economics. He has coauthored a bok in the field of industnal organization entitled, Size. Profits and Executive Compensation in the Large Corporation, which devotes a chapter to regulated industries. Dr. Peseau has published articles in the following professional journals: Review of Economics and Statistics, Atlantic Economic Journal, Journal of Financial Management, and Journal of Regional Science. His articles have been read before the Econometric Society, the Western Economic Association, the Financial Management Associatin, the Regional Science Association and universities in the United Kingdom as well as in the United States. He has guest lectured on marginal costing methods in seminars in New Jersey and California for the Center of Professional Advancement. He has also guest lectured on cost of capital for the public utlity industry before the Pacifc Coast e _chment 1 Page 30f3 Gas and Electric Association, and for the Executive Seminar at the Colgate Darden Graduate School of Business, Universit of Virginia. Dr. Peseau and his firm have partcipated with and been members of the American Economic Association, the American Financial Association, the Western Economic Association, the Atlantic Economic Association and the Financial Management Association. He was formerly a member of the Staff Subcommitee on Economics of the National Association of Regulatory Utility Commissioners. Dr. Peseau has been President of Utility Resources, Inc. since 1985. 1 2 3 4 5 6 7 8 9 10 10 ~O.ON..11o:.~~ " :: 0\12 500 coa+¿1 13 .~ ß 4)gooz 14ö.§i 15..-...u:; U4)~ a ~.. 0 16II rt ~5~u 17,-h..o t" o¡ t"18ii 19 20 21 22 23 24 25 26 27 28 e CERTIFICATE OF SERVICE e I hereby certify that I have this day served a copy of the foregoing DIRECT TESTIONY OF DENNS E. PESEAU ON BEHALF OF SNWA in Docket No. 04- 8022 upon each of the paries listed below by facsimile servce as follows: Conne Westadt Sierr Pacific Power Company 6100 Neil Road P.O. Box 10100 Reno, NY 89520-0024 Facsimile (775) 834-4811 Sherr McDonad, Manger Regulatory Servces Sierra Pacific Power Company 6100 Neil Road P.O. Box 10100 Reno, NV 89520-0024 Facsimile (775) 834-481 1 Mar Simmons Sierr Pacific Power Company 6100 Neil Road P.O. Box 10100 Reno, NY 89520-0024 Facsimle (775) 834-48 11 Staff Counsel Public Utilties Commission 1150 E. Wiliam Street Caron City, NV 89701-3109 Facsimile (775) 687-6110 Alaina Burtenshaw Public Utilties Commission 101 Convention Center Drive, Suite 250 Las Vegas, NV 89109 Facsimile (702) 486-7206 Tim Hay, Consuer Advocte Bureau of Consumer Protection 1000 E. Wiliam St., #200 Caron City, NY 89701-3117 Facsimile (775) 687-6304 ;:ODMA\POOS\LRNODOS\ 14968\1 Page 1 of2 .e . I Gerad Lopez 2 Senior Deputy Attorney General Colorado River Commission 3 555 E. Washington Ave., Suite 3100 Las Vegas, NY 89101-1065 4 Facsimile (702) 486-2695 5 Bil Kockenmeiser, Esq. 6 6005 Plumas St.~ Suite 301 Reno, NV 89509 7 Facsimile (775) 829-6165 8 Patnck V. Fagan Esq. Allson, MacKenze, Russell, et al 9 P.O. Box 646 ~o 10 Caron City, NV 89702 Facsimile (775) 882-7918~o o C' ..11c: So Charles Hauser,.- l"Southern Nevada Water Authority1 :: 0\12l' 00 i: If-3 100 i S. Valley View Blvd. g ~ t'13 Las Vegas, NV 89153 'B ~Facsimile (702) 258-3803l'Z 14 Q.si 15 Dennis Peseau..-'1"o~()Utilty Resources4) =.c .. 0 16 1500 Libert St., Suite 250 i~~Salem~ OR 97302 . i- I"17 Facsimile (503)370-9566ul" '; r-18 Jacqueline Rombardoc: 19 BCP 1000 E. Wiliam St., Suite 200 20 Caron City, NV 89701 Facsimile (775) 687-6304 21 22 Date this 'Z6lk day of Octobe, 2004. 23 r2 -~ 24 ~ I ~I 25 26 27 28 ::ODMA\PCOO\HLRN0OO14968\1 Page 2 of2 ... ;t,4~ .. .,¡ It'._'.,, .. ;-. ~.,,." ..', . RECEl'lt:O t-~' BEFORE TH PUBLIC UTIITIES COMMSION OF~~WP~S ,~OH!;t,,:~l?~i. . . . .-. . ,", ""; . 03 SEP 1-9 AM 10= 36 In re Application ofNEV ADA POWER COMPANY to ) Amend its Amended Demand-Side Plan of Action for its ) Refied 2000 Resource,Plan. ) ) Docket No. 03-6056 In re Filng by NEVADA POWER COMPAN FOR Approval of its 2003-2021 Electc Resource Plan. . ) ) CDÕek"'t'No:-03'ö700:: ) i PREPAR TESTIMOmOF DENIS E. PESEAU ~,/" Submitted by: ~~.Fre SClini4t ". Hale Lane Peek Dennson an Howa 777 Eas Wiliam Stret, Suite 200 Carn City, NV 89701 (775) 684-6000 Attrneys for SOUTHRN NEVADA WATER AUlHORITY. .'e.e 1 . Q. WH~T TYPE OF IICUSTOMIZED PRODUCTS" DOES NEVADA poweR 2 INDICATE rT NEEDS TO FILL ITS OPEN POSITION? 3 4 .,5 A.In VoJume IV, the Load Fore~ast and Market Fundamentals, Page 17, the Company describes the need for power products for capacity and energy of relatively narrow intervals of a few hours to meet needle peaking nature of it 6 . system. 7 Q. DO THE WATER PUMPERS HAVE THE ABILITY TO PROVIDE NEV~DA' 8 .9 POWER WITH SIGNIFICANT QUANTITIES OF SUCH. CUST,OMIZED . PRODUCTS? 10 A.. Yes. The water pumpers have a significant amount of both demand side and 11 12 .'13 , . supply side products. The abilty to provid~ these custom proQucts. ~s, af course, subject to, Nevada Power's willngness to take advantage of such opporlùnitiEs. 14 . Q. PLEASE GENERALLY DESCRIBE THE POSSIBLE DEMAND SIDE AND 16 SUPPLY SIDE CUSTOM PRODUCTS .THAT COULD BE OFFERED BY .. WATER PUMPERS. 15 ' 17 A.Demand side prod.ucts include those that provide. the abilty for Neva~a Power . to avoid purcl)asing otherwise. scarce and expensive on~peak power supplies... ..18 19.In the case of the retail water pumping loads served by Nevada Power, under appropriate terms and conditons, the water pumpers can interrupt capacit' .20 . -11- .. 2 ,3 4 5 6 7 8 9 10 11 .12 13 14 15' 16 17 18 19 20 '21 1 --- facility located at Apex, Nevada. . The energy produced from this locàl generator is capable of shaping to accommodate a maximum. of output, consumption in the off peak for water pumping, leaving the plants peak capacity and energy available for customers of Nevada Power~ Finally, Nevada Power is requesting in its filing to êxpend $500,000 over the next two years to study the feasibilty of an undesignated coal plarat. As part of its ongoing efforts to minimize energy costs and satisfy its gro~ing. . . , load requirement, the SNWA for some time hås been exploring the economic, . feasibilit of owning a share of a coal plant and has already committed $1,000,000 to study new coal generation feasibilty. Just as Nevada Power's, Reid Gardner 4. coal plant Jointly owned .by Nevada Power a.nd the water pumping California State Agency (DWR) is an example of a succes~ful private/publicpartnership in electric generation, the study of a 'cò.venture between Nevada Power and the SNWA could be very beneficial to Southern Nevada. It is also important to reconize that SNWA's DoubleM- credit ' rating from Standard & Poor's is certinly unique among power producers aliØ 'electric utilties in general. Q.WHAT DO YOU SPECIFICALLy'RECOMMEND? . , A,Nevada Power should pursue resource options with SNWA and report back to the Commission within six months or at least prior to the 2004 peaking season. In the interim, the Commission should defer approval of Nevada -13- 1 2 3 4 5 6 7 8 9 10 11 12 13 14 ,15 16 17 18 19 20 21 e It and energy supplied for most of their internal load requirement for four or so hours on summer peak days. Of course, this doesn't even up to include several hundred additional MWs of SNWA load supplied by'CRC. Nevada Power was unable to locate and purchase this type of custom product in the past few summer seasons. Another very valuable demand side custom product potentially available to Nevada Power is an enhanced abilty to protect system reliabilty ,by coordination of load shedding abilities off of SNWA transmission laterals und~r instances of system emergencies. Q.WHAT WATER PUMPING RESOURCES ARE POTENTIALLY AVAILABLE TO FILL NEVADA POWER'S OPEN POSITION? A.In the near-term, the water pumpers either have, or wil have substantial power under contract to meet its own loads that are not served by Nevada' Power. Typically. the economics of minimizing costs dictates that the power provided under these contract be .shaped into a maximum amount of off peak usage for water pumping, and the remainder resold into higher priced peak , wholesale markets. This large amount of peak capacity and energy product is likely to be a near pertect match'to fill Nevada Power's needle p~akirigload profile. By next summer, the SNWA intends to add to its power supply program the 125. megawatt share of the Silverhawk combined cycle combustion turbine -12- e - 1 Powets three. year action plan request for approval of $500,000 on a coal. . . . 2 project feasibi!it study. 3 NEVADA POWER'S CAPITAL EXPENDITURE BUDGET IS AT RISK 4 . Q. . WHAT 15 THE ISSUE WITH RESPEC.TTO NevADA POWER'S PROPOSED '5 , CAPITAL EXPENDITURE BUDGET? A.Even with a modest level of required capital expenditures Nevada PQwer would be challenged to finance investment on reasonable terms at reasonable 6 7 9 .: cost~. Nevada Powets projected budget for capital expenditures is anything but modest. Table 4-3, page 298 of Technical Appendix II in the Company's filing reflect the following total capital budget: ,8 10 1'Capital. 12 Year Re.guire'ment 13 2004 $347,435,000 14 2005 .448,151,000 15 2006 448,505,000 16 2007 399,885,000 17 2008 440,861,000 18 2009 566,409,000 19 2010 477,753,000 21 22 ,Attachment -A of the Company response to Bep 2-28; inctuded as my Exhibit.,_.(DEP-1). breaks down the annual capital investment by function. For the period of the Action Plan. 2004-:2006 alone, the capital requirements are 20 -14- "e e 1 $ 1.2 billon. The issue is whether Nevada Power's desire to begin iss,uing 2 .3 4 dividends of $53 millon per year, beginning January 1, 2004 is consistent with the financial stature necessary to raise, such large amounts of capital while maintaining a healthy capital structure", . 5, .Q. 6 A. 7 8 9 10 11 12 13 14 WHAT IS A HEALTHY CAPITAL STRUCTURE? A healthy capitl structure is a balanced proportion of outstanding debt ,~nd common equity suffcient to attr,act additional 'capital- both debt and equity:- on reasonable terms. Nevada Power for years has had far'too much debt, also termed excessive "leverage", in itS' capitl structure. Recognizing 'this high degree of le,verage, and the reluctance of Nevada Power to issue ample , common stock, the Commission .in Docket 02-4037 prohibited the CQmp~ny from issuing dividends to Sierra Pacific Resources until either thè Company hit a target of 42% equity ratio as a perèEmtage of total capital. or becemb,er 31,2003. .'. 15 Q. WHAT IS THE CURRENT EQUITY RATIO OF NEVADA POWER? 16 A. 35%; as indicated on page 82 of Volume Vl of the Integrated Resource Pla~ '17 2003. ~15- "e e .1 Q.WHAT ARE THE FINANCIAL CONSEQUENCES OF THE 3~%. EQUITY : ..2 RATIO? 3 A.There are two very negative consequences attched to this row equity ratio. 4.One, the low equity ratio means too high of a debt ratio. Too high of a debt .' 5 ratio raises the interest rate which Nevada Power must pay for new qebt.. 6 . Second, the low equit ratio disqualifies Nevada Power from regajning 7 investment grade credit .ratings. Nevada Powets debt is currently raie~.at 8 åjunk..level, or below investmel1t grade. .. 9 Q.DOES NEVADA POWER HAVE A TARGET. EQUITY RATIO? 10 A.Yes.The Company's target equity ratio. is 42% (page 82, Vol. Vi, IRP). 11 Nevada Power indicates that a 44% actual equity ratio is needed to. regain ..12 investment grade ratings (pagé 85, Vol. Vi, IRP). 13 Q. HOW IS THE EQUITY RATIO INeREASED? 14 A. The equit ratio can be increased by financing the capital budget with new 15 16 issuances of common stock, and/or through internally generatèd funds in the form of retained earnings. -16- e e 1 . Q. DOES NEVADA POWER INTEND TO ISSUE NEW COMMON STOCK? 2 A.. No, not until at least the year 2010. My Ex~ibit..jDEP-2) reproduces .thè 3 external financing plans of the Company (pg. 298, Tech. App.lI). All financing- ,. 4 .prior to 2010 is debt. 5 Q. DOES NEVADA POWER INTEND TO' REDUCE ITS EXTERNAL 6 . FINANCINGS BY MAXMIZING INTERNAllY GENERATED c;APITAL FUNDS?7 8 9 10 A.No. Nevada Power intends to rèduce its intemally.generated funds by åt least . $ 53 milion per year .and issue a like amount to its parent in the form of divdends for years 2004, 2005 and 2006 (pg. 80, Financial Plan, Vol~ VI). ,. :. . 11 Q TOWHÄT OTHER PURPOSE SHOULD NEVADA POWER APPLYTHE $ 53 . 12 MILLION PER YEAR IN DIVIDENDS? 13 A. .. A more prudent use of the annual cash of $ 53 millon is to reduce the annual 14 amount of projected debt issuances by an eqùal amount., Nevada Power 15 presently and wil for years fåce a diffcult market for its debt. In its most, 16 recent finance docket. Nevada Power had to refinance unsecured .6% debt for 17 secured 9% debt despite the fact that market interest rates had not moved. 18 Nevada power's plan to issue $ 53 milion in dividends to its parent simply 19 . removes this amount of otherwise readily available capital from internal funds -17- . .e .e 1 2 and requires a like amount of expensive, poorly rated debt to be issued, further .Iowering its equity ratio. 3 . Q. WILl NEVADA POWER FACE ADDITIONAL DEMANDS FOR ITS CASH IN 4 THE NEAR FUTURE? A.. .Yes., Unless the recent decision of the U.S.. bankruptcy court is reversed, Nevada Power wil need approximately $ 229 millon in cash in the nearfuture. 5 6 7 Q. WHAT PRACTICAL CONSEQUENCES WILL RESULT FROM NEVADA 8 9. POWER'S DIVIDEND PROPOSAL? A.The proposed dividends and their êffect of rèducing the already low equit 10 ., , ratio. wil significantly increase the likelihood that Nevada Power wil. ~ot be " .11 12 13 able to meet the level of capital expenditures contained in its resourcèplan. ... j., 14 15 With its 3000 megawatt open position and its modest amount of self owned generation, the transmission and generation expenditures in the budget are crucial for mainiaining system .reliabilty in southern Nevada.. As was the . position in the last resource pla~ docket, the SNWA continues to recommend. that the capital budget be maintained at the highest levels. In particular. .16 .17 18 . . Nevada Power should conserve its internal funds to ensure the timely completion of the Centennial Transmission Project prior to the 2007 peak. -18- ; 1 2 3 ' 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 e e NEVADA POWER'S REQUEST FOR PRE-APPROVAL' OF DEFERRED ENERGY COSTS SHOULD BE 'DENIED . Q. WHAT IS THE ISSUE WITH RESPECT TO NEVADA POWER'S REQUEST TO HAVE THE COMMISSION IN THESE PROCEEDINGS PRE-APPROVE COST RECOVERY REVIEWED IN DEFERRED ENERGY.AND GENERAL RATE CASES? A. T~roughout the Company filing, the request is made to approve a "Recommended Gas Hedging Strategy".1 While resource plans, action plans, strategies and specific 3-year capital expenditures are normal!y in the purview of IRP proceedings, the Company requests regarding the approval. of a uGas . . Hedging Strategy" apparently goes far beyond resource plan proce~dings., . Nevada Power's request is actually for the pre-approval of several hundred millon dollars of natural gas costs for gas. yet to be purchased, but normally. , . . reviewed in deferred energy proceedings. Q.PLEASE EXPLAIN. A.Nevada Power's proposed Hedging Strategy requests approval fortwo distinct expenses: one, the recovery of natural gas costs in 2004 incurred for both its . own plants and the cost of the e'~ctricit purchased through the anticipated tollng agreements to fin its 3000 megawatt open position and, two, recovery for the expenses attributable to the prop~sed call option~ on 100% of the gas 1 SeèApplication Pages 7-8; Yachira. Page 6. L1nes 17.21; Ivery, Page 3, Lines 6-9; Action Plan, Pages 2-3; Vol. I. Page 16; Vol. II. Pages 2, 45. -19- e e 1 2 for both its plants and tolled purchases at a strike price that is $0.50 "out..f- 3 4 5 Q. ARE FUEL AND FUEL ACQUISITION COSTS NORMALLY APPROVED IN 6 'ADVÅNCE OF PURCHASES? 7 A., No, in the several fuel cost recovery proceedings in which I have participated,. . . . 8 . recovery of fuel costs is granted subsequent ,to the actual incurring, of these 9 , costs. 10, Q., ARE FUEL AND FUEL ACQUisitiON COSTS USÚÀLL Y APPRÒVED IN "11, RESOURCE PLANNING PROCEEDINGS?" ' 12 A. No, not in Nevada. . 13 ' Q. PLEASE ESTIMATE THE LEVEL OF FUEL AND F~EL ACQUISITION 14 EXPENSES FOR 2004 ALONE THAT THE COMPANY IS SEEKING. 15 A.The following table summarizes the four distinct areas of ' cost recovery lhet ' .16 Nevada Power is. requesting for fuel and fuel acquisition costs: ' -20- ;; 1 2 3 4 5 6 7 8.9 10 11 12 13 14 15 16 11 .18 19 20 21 e.e Annual Exp~nse (milions) Natural Gas for Own Generation 1 Call Options for Own Generation2 Exposure for Tolled Generaliòn3 .Call ,Options for Tolled Generation" $196 20 370 18 Total. NPC Cost Recovery Request $6Ó4 milion As shown in the table, the single point fuel cost estimate for the 2004 recovery request of Nevada Power is $604 milion, which includes the cost of physical : gas and hedges .for its own generation resources, plus the cost of physical ga~ and hedges for the gas that is procured for the tollng agreements associated with the proposed RFP. The estimate assumes that the cost of call options is only $.025 per mcf and the tallng capacit factor is 45%, each of which 'may . be conservative. Q.WHAT APPROXIMATE AMOUNT OF THE TOTAL DEFERRED ÈNERGY COSTS NORMALLY REVIEWED IN DEFERRED ENERGY COST. PR.OCEEDINGS DOES THE $604 MILLION REPRESENT? 1Psge 3~. voi. II 2Assumed $.25 price of option altough it is likely this number's much higher. . 3Exhibit ~ (DEP.3) 4Assumed $.25 price of option although it is likely this number is much higher. -21- --- 1 A. Up to 80% when compared to total fuel and purchased power BTER expenses' 2 in Docket No. 02-11021. The only significant remaining costs left aut of this 3 ';hedging strategy" are those associated with coal, oil and certain. other 4 miscellaneous items. Most of the purchased power (tollng) and natural gas 5 costs are included in the hedging strategy. 6 Q. WHAT iS YOUR RECOMMENDATION WITH REGARD TO APPROVING 7 THE HEDGING STRATEGY? 8 A. The hedging strategy is nothing mare than making natural gas purchases .on . 9 the spot market at market prices, with a call aptian for strike prices. out of the 10 money. I recommend that the Commission defer any explicit or. implicit .. 11 approval of the costs incurred as a result of any purchasing. and hedging 12. strategy to the next deferred eriergy cost proceedings. 13 14 DEFER DECISION ON PRUDENCE OF COSTS OF GAS CALL OPTIONS 15 Q. WHAT IS THE ISSUE REGARDING NEVADA POWER'S RECOVERY OF 16 THE COSTS IT INCURS TO SECURE CALL OPTIONS FOR NATURAL 17 GAS? 18 A. In the previous deferred energy proceeding, Nevada Power indicated that, 19 while call options pravidè protection, they have a significant cost (Reid 20 21 Deposition, Exhibit 2) the October 15, 2001 memo toRN1C. Given the significant cost of call options then, Nevada Power decided to cover a small -22- '. 1 2 3 4 e..e portion of its natural gas purchases with these options. T~e issue here is whether the Commission in this resource plan proceeding should authorize or. . endorse the level of costs that the Company would incur in going' now to a 100% call option strategy.. . '5 Q. WHAT WILL BE NEVADA POWER'S COST OF CALL OPTIONS UNDER 6 7 8. 9 10. 11 .12 13 .14 15 16 17 18 19 20 21 ITS 100% PROPOSAL IN THE RECOMMENDED GAS HËDGING. . STRATEGY? A.We, of course, don't know in advance. In Nevad~ Power testimony rlÌ rJcket No. 02-11021, the Company indicated that "collar options" which are less, . expensive than the call options proposed in its Recommended strategy, we,re 5-10 cents per mcf (Reid, Direct, Page 5, Lines 13~14l as modified órally at hearings). The cost of natural gas call options as of the time ,of the writing of. my . . testimony was between. 70 cents and 84 cents per met for December 2003 natural gas. Call options for periods beyond December would be much higher., , As an "orders of magnitude" estimate for,the call options propnsed by ., . Nevada Power, i use a 7.5 cent per met cost, and the gas quantities I developed in Exhibit ~ (DEP-3). The estimate of the cost of j'ust these financial instruments, with no physical gas associated wih it, is.$85 millon per year (.75/5 · 566). -23- '.-,e 1 2 Q.HOW DO YOU RECOMMEND THE ISSUE OF THE RECOVERY OF CALL OPTION COSTS BE CONSIDERED BY THE COMMISSION? 3 A.First, I recommend that Nevada Power provide additional testimony on its 4 position on this issue, given that the market price for call options. has . 5 increased so much from the time its strategy was originated. 6 Second, 'given the uncertainty and t~emendous costs today of. call 7 options, the Commission should defer any decision on the appropriate levels. . 8 . of options costs into the more appropriate setting of the deferrd energy 9. proceedings. In this way the timing and prudence of the options could be. . . . 10 appropriately evaluated... .11 . REQUIRE ADDITIONAL ANALYSIS BEFORE 12 LOCKING INTO 100% LONG TERM CONTRACTS. . ,.13 .Q. WHAT IS THE ISSUE REGARDING NEVADA POWER'S REQUEST TO BE 14 AUTHORIZED TO ENTER LONG~ TERM PURCHASED POWER CONTRACTS TO FILL ITS LARGE OPEN POSITION?15 16 A.. Nevada Powets request for approval of its long-term RFP process and a. 18 100% hedged position for its financial gas exposure will lock ratepayers into a huge financial. commitment. 17 19 I am generally not opposed to a considerable intermediate or long-term purchased power position, but any such decisions must be weig~ed with risk and portolio mix considerations.. The issue is whether the timing of this .. 20 21 -24-: 1 2 3 - 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 A. e e resource plan coupled with the extremely weak finance position of Nevada. . Power make this a prudent time to lock significantly into lorig-term RFP contract. Q.PLEASE EXPLAIN. A.Prior proceedings, have made evident. the very weak. finàncial position of Nevada Power and the credìt.risk considerations that all vendors will ~eigh. when proposing to sell to Nevada Power.' Credit-risk premiums grow exponeritialfy with time. Thus, the terms and conditions under which a power . supplier would sell to Nevada Power must become much more onerous u~der a ten year contract than under, say, a one~year summer peaking contract. The proposed toiling agreements have little effect on these risk premiums. Q.WHAT IS YOUR RECOMMENDATION ONTHE ISSUE OF NEV~DAPOWER LOCKING INTO SIGNIFICANT AMOUNTS OF LONG. TERM PURCHASED POWER CONTRACTS? The actual dégree to which customers are going to be asked to assume a credit risk premium cannot be known until the long term RFP process is: completed and Nevada Power has filed its Amended Plan. I urge the . Commission to set aside suffcient time to evaluate the results of this process. . and order any changes to the purchased power resource mix that it concludes is warranted. ~25- e..e 1 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 2 A. Yes:' -26- e ... ., , '";; ~ .' ~~5~........ ..i fii I:i t'" . J Iiill! ~iltiIii.-~l~1 . ~ Exibi t . DEP 1 Page i ori. e e .~~. . " ~'. ....... Exhibit (DEP 2) Page 1_ oFT -.. . . . " Yen Debt Jlr~m'ÐlClUr Tr.tl 2003 iso,oo .... '. 350,002.10000 ...100,(1 20$.......~203.00 ....203.00 200 179,00 .." ..I7MlO..;."200 264.00 . '.~~,OO20690,00 ....00,00 2010 (132.00)..44Ó;o'.' .30&00 2011 oiSS.CJ ..199.00 ßl.ÐO :101i 152.00 ...n5.00 261.00 . 2013 71fI ..-'5400 U1.00 2014 186.00 ..133.00 31l.ÐO ~i$17200 ..124ÐO 298.00 ioi6 161.00 ..- 1J6.00 "11,00 2017 n.oø ..5200 12.4,(1 2l)iS I~OO ...is.oo 20.00 2.019 l~OO ..&5.00 241.00 202 109,00 ..5.00 114.00 101 (1,00).(1.00 (200) ¡on 191,00 ..i.'".00 . T..wc 4-4 Ilnd Fim 4- SuDUIy oftdnul FJAheng (S li 'lollswI) . . , ;l l " N e v a d a P o w e r s ' e s t i m a t e o f Na t u r a l G a s , F i n a n c i a l E x o s u r e Ca p a c i t y F a c t r It e m . M W 0. 3 5 .0 . 4 0 0. 4 5 0. 5 0 . 0 . 6 0 To l l n g p u r a s e s 1, 5 0 0 $1 7 2 , 4 6 2 , 5 0 0 . $1 9 7 , 1 0 0 , 0 0 0 $2 2 1 , 7 3 7 , 5 0 0 $2 4 6 , 3 7 5 , 0 0 0 $~ 9 5 , 6 5 0 , O O O 2, 0 0 0 $2 2 9 , 9 5 0 , 0 0 0 $2 6 2 , 8 0 0 , 0 0 0 $2 9 S , 6 5 0 , O O O $3 2 8 , 5 0 0 , 0 0 0 $3 9 4 , 2 0 0 , 0 0 0 25 0 0 $2 8 7 . 4 3 7 . 5 0 0 $3 2 8 , 5 , 0 0 . 0 0 0 $3 6 9 5 6 2 , 5 0 0 $4 1 0 , 6 2 5 . 0 0 0 $4 9 2 . 7 5 0 . 0 0 0 Ph v s l c a l P u r c h a s e s . $ 1 9 6 . 0 0 0 0 0 0 $1 9 6 . 0 0 0 0 0 0 $1 9 6 0 0 0 . 0 0 0 $1 9 6 , 0 0 0 , 0 0 0 $1 9 6 . 0 0 0 0 0 0 - To t a l F i n a n c i a l E x p o s u r e : Mi n i m u m $3 6 8 . 4 6 2 , 5 0 0 . $3 9 3 , 1 0 0 , 0 0 0 ' $ 4 1 7 , 7 3 7 , 5 0 0 $4 4 2 , 3 7 5 , 0 0 0 $4 9 1 , 6 5 0 , 0 0 0 Ma x m u m $4 3 . 4 3 7 5 0 0 . $ 5 2 4 . 5 0 0 , 0 0 0 $5 6 5 5 6 2 , 5 0 0 $6 0 6 . 6 2 5 , 0 0 0 $6 8 8 , 7 5 0 , 0 0 0 . As s u m p t i : ' He a t Ra i e fo r To W r i g 7 , 0 0 b t u l k Ga i C o s t 5 . 0 0 $ J \ U .' - ': r i " () : : t\ I - ,~ ~ I ; ~i r t . " , ' .. , . ' . , ' ~'i (. eo' AFFIRMATION e I, Dennis E. Peseau, pursuant to NAC 703.710 hereby affirm that the. foregoing prepared testimony was prepared by me or under- my ,direction and is correct to the best of rry knowledge. Signed !2;a4U. Dated September 19 t 2003 rl e,e Attachmeit "1 Page 1 of 3 STATEMENT OF OCCUPATIONAL AND EDUCATIONAL HISTORY AND QUALIFICATIONS DENNIS E. PESEAU Dr. Peseau has conducted economic and financial studies for regulated industries for the past twenty-eight years. In 1972, he was employed by Southern California Edison Company as Associate Economic Analyst, and later as Economic. . Analyst. His responsibilties included review of financial testimony, incre~ental cost , studies, rate design, econometric estimation of demand elasticities and various a~eas" ' in the field of energy and economic growth. AI~oi he was asked by Edison Electrical Institute to study and evåluate several prominent energy models as 'part of.the Ad Hoc Committee on Economic Growth and Energy Pricing. From 1974 to 1978, Dr. Peseau 'was en:Ployed by the Public Util~ty Commissioner of Oregon as Senior Economist. "There he conducted a number of . economic and financial studies and prepare testimony pertaining to public utilites. In 1978 Dr. Peseau established the Northwest offce of Zinder Companies, Inc. He has since submitted testimony on economic and financial. . . . matters before state reg~lat~ry commissions in Alaska, California, Idaho, Maryland, Minnes~ta, Montanà. Nevada, Washington, Wyoming, the District of Columbia," t~e Bonnevile Power Administration and the Public Utilties Board of Alberta on over one h"undred occasions. He has conducted marginal cost and rate design studies and e,.e Attachment 1 Page20f3 prepared testimony on these matters in Alaska, California, Idaho, Maryland, Minnesota, Nevada, Oregon, Washington ~nd in the District of Columbia. He has . also conducted cost and rate studies regårding PURPA issues in the states of Alaska, California, Idaho, Montana, Nevada, New York, 'Washington, and Washington, D.C. Or. Peseau holds the B.A., M.A. and Ph:D. degrees in economics... , ,. . , He has co-authored a book in the field of industrial organization en~tl~, " Size. Profits and Executive Compensation in the Large' Corooration, which devotes a chapter to regulated industres. Dr. Peseau' has published articles in the following professional journals: Review of Economics and Statistics, Atlantic EconC?mic Journal, Journal of Financial Management, and Journal of Regional Science. His articles have been read before the Econometric Society, the Western Econ~mic' Association, the Financial ~anagement Association, the Regional Science Association and universities in the United Kingdom as well as in the United State. He has guest lectured on marginal costing methods in seminars in New Jersey and California for the Center ,of Profession~1 Advancement. He ha.s also guest lectured on cost of capital for the public utilty industry before the Pacific Coast, . Gas and Electric Association, and for the Executive Seminar at the Colgate Darden . Graduate School of Business, University of Virginia. .e Attachment 1 Page 3 013 , . Dr. Peseau and his firm have participated with and been members of ~e Ameriçan EConomic Association, the American Financial Association, the Western. ~ . Economic Association, the Atlantic Economic Association and the Financial Management Association. He was formerly a member of the Staff Subcommittee on Economics of the National Association of Regulatory Utilit Commissioners. Dr. Peseau has been President of Utilty Resources, Inc. since 1985. " i I I. e,. PROOF OF SERVICE' I hereby certify that I mailed the foregoing Prefiléd Testony of Dens PeSea in Dockets 03-6056 and 03-7004 by delivenng to the U.S. Post Offce copies therf, properly addressed for mailing to the followig persOns: Conne Westadt Nevada Power Company P.O. Box 10100 Reno, NV 89520 . Cheryl Hachman Nevada Power Company P.O. Box 10100 Reno, NV 89520 Tim Hay Burau of Consuer Protection 1000 E. Willam Str Carson City, NV 89701 John Nielsen Wester Resources Advocates 2260 Baseline Road, Suite 200 Boulder, CO 80302 . Jon Wellnghoff .Beckley Singleton 530 La Vegas Blvd. South Las Vegas, NV. 89101 Gerad Lope Colorado River Commission 555 E. WaShington Avenue, Suite 3100 Las Vegas, NV 89101. James Ross . RCSIDc. 500 Chesterfeld Center, Suite 320 . Chesteld, MO 63017 e . Michael Alcata Alcanta & Kah LLP 1300 S. W. Fift Svenue, Suite i 750 Portand, OR 97201 John Gezelin 436 Cour Street Reno, NV 89501 Wiliam Gehlen Teeo Power Serice 702 N. Fralin Strt Tam~ FL 33602 . Dale Stransky . Buráu of Consumer Protection 1000 E. Wiliam Street, Suite 200 Caron City, NV 89701 Erc Witkoski Bureau of Consuer Protection 555 E. Washington, Suite 3900 La Vegas, NV 89101 John Nielsen Energy Project Director Wesern Resour Advocate 2260 Baseline Road, Suite 200 Boulder, CO 80302 Dated: Septeniber 19,2003 e ~- .1 ". B~FORE THE P,UBLIC UTILITIES COMMISSION OF NEVADA pocket No. 03-7004. Direct Testimony of Dennis E. Peseau on behalf of Southern Nevada Water Authorit 1 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 2 A. My name is Dennis E. Peseau. My business address is SU,ite 250: 15QO 3 , ,Libert Street, S.E., Salem, Oregon 97302. 4 Q. BY WHOM AND IN WHAT CAPACITY ARE YOu" EMPLOYED? 5 A. I am President of Utilit Resources, Inc. My firm consults on a numbår ~f . 6 7 economiè, financial and engineering matters for various' privåte a~d public entities. 8 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? 9 A. I am testifing on behalf of the Southern Nevada Water Authorit (SNWA). -1- _..,.e 1 Q. . DOES ATTACHMENT 1 ACCURATELY DESCRIBE YOUR BACKGROUND 2 AND EXPERIENCE? 3 A.Yes. 4 Q. 5 A. 6 7 8 ,9 10 11 12 '13 14 15 16 17 18 19 20 . 21 WHAT IS THE PURPOSE OF YOUR TESTIMONY? My testimony focuses primarily on five areas or issues which I iØenti below. To place these issues in perspective, l note that the overall tenòr of., " Nevada Power's filed Resource Plan is the commitment to an ambitious' capital expenditure program to greatly expand the.Company's own generation and transmission plant over the next decade. The SNwA has provided .' testimony in prior Nevada Power dockets including resource plans and continues now to recognize and point out the inadequate level.of internal, . generation and transmission resource additions made to the Nevada Power. system over the last decade or mote. New i:dditions are necessary and vital to the electrical systems,.relíabilty in southern. Nevada. The SNWA heartil, . supports the timely completion of necessary transmission and generation facilities. But a number of Nevada Power's financial proposals in its filing, and circumstances external to its Plan, are simply incompatible . with the . Company's proposed new generation and transmis~ion expenditures, and its abilty to maintain any se~blanCe of financial stabilit at rate le,relsthat are acceptable to its customers. -2- e e 1 I point specifcally to its plans to issue over $1.7 bilion in debt but rio equity over the period 2003-2009 and its decision to begin using projected2 3 available cash to spend in dividends rather than finance new generation and 4 transmission facilties. The most recent external circumstance I refer to is the 5 August 29. 2003 adverse ruling by a U.S. bankruptcy court to issue summary 6 7 judgment for Enron against Sierra Pacific Resources regarding Enron's tlaim for liquidated damages. Instead of outlining corrective measures to regàiri it finanCial foothold while making crucial investments. Nevada Power instea~ requests a pre-approval of some $400-600 milion per year in expenses that have historically been scrutinized in deferred energy and general rate cases. This testimony wholeheartedly supports and encourages the generation 8 9 10 11 12 13 and transmission investment necessary to meet present and growing electricity requirements and offerS alternatives to Nevada Powe'r's'proposals. 14 Q. 15 A. 16 17 18 19 .20 21 '22 23 24 25 26 WHAT ARE THE FIVE PRIMARY ISSUES YOU ADDRESS? The five issues are: 1. Nevada Power should avail itself of purchased power products that are suited to its unique summer needle peaking load profile. rather than continued excessive reliance upon 6x16 or similar high energy products purcliased previously. The SNWA has a uriiq'ue load profile and its. own signifcant resource products which Nevada Power should avail itself of or fully evaluate to help avoid the large credit-risk premiums being demanded of the Company by vendors on the open market. 2. Nevada Power proposes in this proceeding to begin giving $53 millon per year of its scarce cash flow to its parent Sierra Pacific Resources beginning January 2004. Given Nevada Powers -3- .'e..- 1 2 3 4 5 6 7 deteriorating capital structure, such an action is even more ii- advised than when the Commission restrcted such dividends1n Docket 02-4037. The Company's abilit to complete the important Centennial and Harry Allen-ta-Mead new transmission projects, as well as its proposed generation will not be able to be, financed at reasonable'costs if Nevada Power gives up this cash flow. 8 9 10 11 12 13 .14 3. Nevada Power proposes perhaps the most.', sweeping guaranteed cost recovery mechanism in Nevada's regulatóry history in this Resource Plan docket Some $400-600 milion in fuel. and purchased power costs per year are being requested to be pre-approved in this docket, removing .the typical and appropriate revie\Vgiven these expenses in deferrd energ and general rate cases; . 15 16 17 18. 19 20 21 22 23 24 .25 26 27 28 4. In conjunction with its request for pre-approval óf most fuel and PP-expenses, Nevada Power requests that the Commission. approve the cost of the call options it has already entered into and those it proposes to enter. Recovery of these costs is appropriately decided outside of a resource plan proceeding. Any decision regarding call option hedging strategies should be evaluated in deferred energy rate proceedings. 5. Nevada Power is proposing to move from its policy in recent years of purchasing wholesale power 100% on tl1e short-term market to, in this case, purchasing aa signifc~nt" amount on the . long-term wholesale market. Proper risk diversification. techniques would. suggest a more balanced or aportalio" mix of purchases. Nevada Power has not provided adequate risk . analysis in this regard. 29 CONCLUSiONS AND RECOMMENDATIONS 30 Q. PLEASE SUMMARIZE YOUR. RECOMMENDATIONS. 31 A..I recommend that the Commission: 32 33 1.Order Nevada Power to fill its huge open position with den:and and supply side resources that both fit its load profile ~~d -4 ,e,e 1 2 3 4 5 6 minimize costs. Nevada .Power should, during the next six .months explore with the SNWA the unique load characteristics and resources SNWA has available in Nevada Power's service territory. The $500,000 in thre year action plan funds requested by Nevada Power for a coal study should be deferred until Nevada Power reports, back on its progress with SNWA. Order, . or put Nevada Power on notice that it wil order the Company to conserve cash by prohibiting dividends to "is parent until a 42~d equity ratio is reached. Deny Nevada. Powets request for approval .of ,itsuRec9mmerided Gas Hedging Strategy" in th~se proceedings and defer any such decision to the next deferred energy case. 4. ' Defer any decision on the appropriate expenses for Nevada Powets proposed natural gas call options to the next deferred energy case. 2.7 8 9 10 11 12 13 14 15 16, 17 18 19 20 3. " . . 5. . Require Nevada Power to furt~er study and report back on .an appropnate purchased power portolio mix before enacting its proposed movement from the previous policy of purchasing 100% on the short-term market to purchasing ås much as 100% .on the long-term market. . ,21 FILLING NEVADA POWER'S 3.000 MEGAWATT-OPEN POSITION. .' 22 Q.WHAT IS THE ISSUE WITH RESPECT TO NEVADA POWER'S FILLING OF . 23 ,24 25 2e 27 ITS HVGE POWER SUPPLY SHORTFALL? A.As the Company. explains throughout the supply side plan, energy supply plan and financial analysis plan portions of it filing, Nevada Power has tlie daunting task of procuring at least half of its required power supply from source~ as yet unidentifed. The Company proposes to fiU the deficit C?f up to 3,000 megawatts per year by the issuance of-an RFP designed ,ta acquire28 -57 e e 1 2 3 4 5 6 7 8 long-term purchased power contracts'of 3-1. 0 years. While Nevaaa Power has recently been unsuccessful. according to its testimony in other pròceedings" in attracting responses from vendors in RFPs, I agree with its assessmentthat the temporary apparent adequacy or even slight surplus of regional generation may change these generators willngness to respond to long-tenn contracts. The issue is whether Nevada Power wil be able to attract the rather. unique and ,specialized energy products it requires to optimally fill its needle-pea~i~g load shapes. 9 Q. WHY DO YOU QUESTION WHETHER.NEVADA POWER CAN ATIRACT 10 THE PARTICULAR PURèHASED POWER PRODUCTS IT NEEDS? 11 A. In the last two deferred energy proceedings Nevada Power argued for cost .12 recovery for losses it incurred from having to resell excess energy resulting 13 from contract based upon almost exclusively 6x16 purchases. That is. 14 Nevada Power felt that in order to fill its open position it was force to enter 15 contracts requiring it to purchase energy six days a week, for sixteen hours pér 16. day. Since Nevada Power typically only needs peak energy for four to eight 17 hours per day. these previous 6x16 energy contracts caused Nevada power 18 to acquire substantially more energy than it needed. The excess was sold at .19 huge losses. -6- e...tt 1 The question that arises in this filing is whether Nevad~ Powerwil h~ve opportunities through its proposed RFP process ,to obtain othér than 6x16 energy product. 2 3 4 Q. DOES NEVADA POWER'S RESOURCE PLAN FILING EXPRESS THE A. ,HOPE THAT IT MAY THROUGH ITS RFP PROCESS, FIND WILLING PARTICIPANTS TO ENTER INTO SYNTHETIC TOLLING AGREEMENTS FOR POWER, THEREBY REDUCING ITS 6X16 OBLIGATIONS? Yes. The possibilty of entenng synthetic tollng agreements is mentioned at : a number of places in the Company's. application, testimony and exhibits. 5 6 7 8 9 10 Q. WHAT IS,A "SYNTHETIC. TOLLING" AGREEMENT?.. . 11 A. Tollng is a means bY which a utilit such as Nevada Power can àcquire leg~1 12 13 14 15 16 17 rights to çapacity of a particular ge'neratiiig plant owned by an independe~t part by agreeing to pay (usually) fixed demand charges. . A synthetic tollng agreement is similar"but not necessarily'tied to a particular plant. A.nyenergy . outpul requested by Nevada Power is charged to the Company by the . independent part on the basis of the market price of gas and a heat rate, or by Nevada Power actually acquiring and providing the actual supply. -7- e It 1 . Q. IS THE EXPECTATION BY NEVADA POWER OF THE OFFERING OF. " . . 2 3 4 '.5 6 7 8 TOLLING .AGREEMENTS BY OTHERS REASONABLE? A.At s~me set of prices and' terms this expectation is reasonable due to .an apparent present adequate or surplus of independently owned generating . 'capacity in the western U.S. i~ independent owne~ of. generation can , negotiate tollng prices and terms that exceed those they could get on the: ' . open 'market, it is reasonable .to assume they wouid.r~spond to. Nevada Power's proposed RFP. .9 Q.: IN YOUR OPINION WILL NEVADA PÒWER FACE PAYING A CREDIT ..RISK 10 11 PREMIUM FOR ANY SUCH TOLLING AGREEMENT? A.Yes. Due to Nevada Power's financial cirçumstances it is reasonable to, . 12 assume that any long-term agreement. trillng or otherwise, wil have an , . .13 associated credit premium attached to it.14' 15 Q. WILL THE HOPED-FOR TOLLING AGREEMENTS LIKELY PROVIDE 16 17 18 19 20. POWER SUPPLY OFFERS THAT WILL IMPROVE UPON THE PAST 6X16 . LONG..TERM PURCHASES? A.Yes, although the more.concentrated the purchases are made to confo,rm to only the highest peak hours of the day, the higher wil be the capacity and, probably, energy premium charges associated ~ith any tollng contràct. Thé -8- e .e 1 2 value to Nevada Power and its customers of such narrower peak power is, of course, enhanced as well. 3 Q. . . WILL NEVADA POWER liKELY BE ABLE TO FILL MOST OF ITS PROJECTED 3,000 MEGAWATT OPEN POSITION WiTH TOLLING AGREEMENTS? 4 5 6 A.. The Company does not identif what percentage of its RFP process might be 7 filled with tollng agreements. Nevada Power'does, however; indicate that it prefers to fill its open position largely with long-term 3-10 year contrct. .8 9 Q.WHAT. OTHER PURCHASED POWER PRODUCTS SHOU~D NEVADA POWER ATTEMPT TO ACQUIRE TO FILL ITS OPEN POSITION EITHe:R THROUGH ITS RFP OR OTHER NEGOTIATIONS? 10 .11 12 13 .14 15 A.The SNWA and its member agencies, or "water pumpers,!'. together have. . . 16 , 17 18 19 electric loads today in excess 01-200 megaWatt inside the "load control" area . of Nevada Power. Although most of that load is not actually supplied by Nevada Power this load will increase to over 300 megawatts by 2005. The combination of the water pumpers'typically off-peak pumping, the abilit to be 20 . .' . interrupted within limits during on-peak hours, their own significant capacity and energy requirements and a strong financial market credit rating together provide an almost perfect profile to fit Nevada Power's peaking requirements. I am confident that a good faith effort on the part of Nevada Power and the -9- ;_.re 1 water pumpers could lead to the most economical resource to fill a signifi~nt portion of their open position immediately. ' . Furthermore, the recent activities of the SNWA to become a 125 MW participant in the local Silverhawk combined cycle generating plan (w~iCh. is . scheduled. oriline by. next spring), their recent effort. to secure firm . transmission rights, and significant but preliminary analyses into the viabílty . and sitng of fluidized-bed coal-fired generation faciltiè~ could grea~1y assist Nevada Power in its effort to secure additional supply. 2 3 4 5 6 7 , 8 9 Q., PLEASE BRIEFLY DESCRIBE THE NATURE OF THE WATER PUMPERS' 10 11 ELECTRICAL SYSTEM, LOADS AND REQUIREMENTS. . 'A The water pumpers' electrical needs are servea. within Nevad.a Powets 18 , . service territory both as a customer of Nevada Power and' as a wholesal~ customer served by the Colorado River 'Commission (eRe). At present, a significant amount of megawatt water pumping load is served by Nevada Power and up to 125 megawatts p~rchased through .the CRC pnmarily to operate the vast Saddle Island complex (which SNWA owns) comprising . facilties and pipelines necessary to pump water up and into and within the Las Veg~s valley. 12 13 14 15 16 17 19 -10,: ;: .e"-'--'"e r t~C ~l~/ CO p!':'.1 .... I. I ¡: :r~~'.: (:,::n-,.. :"!,!-!BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVAòA ... ", ':' 04 JAH 2 7 PI; 3: 25 Application ofNEV ADA POWER COMPANY for authority to increase its annual revenue requirement for general rates charged to all classes of electrc customers and for properly related thereto. ) ) ) ) ) Docket No. 03-100Òl..,- - . ..~ Application ofNEV ADA POWER COMPANY for approval Of new and revised depreciation and amortization rates.) ) ) Docket No. 03- 10002 PREPARED TESTIMONY OF DENNIS E. PESEAU Phase Three - Rate Design Submitted by: ~~~ Fred Schmidt Hale Lae Peek Dennson and Howard 777 East Willam Street, Suite 200 Carson City, NV 89701 (775) 684-6000 Attorneys for SOUTERN NEVADA WATER AUTHORITY ".,e e BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA DOCKET NO. 03-10001 Direct Testimony of DENNIS E. PESEAU On behalf of Southern Nevada Water Authority Phase Three - Rate Design PLEASE STATE YOUR NAME AND ADDRESS. My name is Dennis E. Peseau. My business address is Suite 250, 1500 libert Street, S.E., Salem, Oregon 97302 BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED? I am President of Utility Resources, Inc. My firm consults on a number of economic, financial and engineering matters for various private and public entities. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? I am testifying on behalf of the Southern Nevada Water Authority (SNWA). DOES ATTACHMENT 1 ACCURATELY DESCRIBE YOUR BACKGROUND AND EXPERIENCE? Yes. ::ODMA\PDOS\HLRNODOS\369790\1 Page 1 of 12 1 Q. 2 A. 3 4 5 6 7 8 9 10 Q. 11 A. 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 e e WHAT IS THE PURPOSE OF YOUR TESTIMONY? My testimony in this rate design phase of this docket addresses two issues. One. I discuss a means to help reduce the greatly increased rate subsidy identified by Nevada Power Company ("Nevada Power") that does not raise the electric rates of residential customers above levels proposed by Nevada Power. Two, i identify and correct a major error in Nevada Power's marginal cost of service study which affects all water pumping rate classes. WHAT CONCLUSIONS HAVE YOU REACHED? i conclude that: 1. Nevada Power's marginal cost study is flawed and does not follow Commission orders. An error in the marginal transmission and distribution study has resulted in a $1.295.188 excess allocation of costs to the water pumping customer classes. This error is specific only to these WP water pumping classes. 2. The rate subsidy discussed by Nevada Power that has increased in this case to $106 milion per year should be reduced only to the extent that Nevada Power in this rate case does not receive authorization to raise its revenue requirement by its requested amount. However, reductions to the Company's request to increase rates could be used to reduce the level of the rate subsidy. ::ODMA\PCDOS\HI.RNODOCS\369790\1 Page 2 of 12 "e e 1 0oYER-ALLOCATION OF COSTS TO WP WATER PUMPING CLASSES 2 3 Q. 4 5 6 7 8 A. 9 10 11 12 13 14 is 16 17 is 19 Q. 20 21 22 23 A. 24 25 26 27 28 HAVE YOU TESTIFIED PREVIOUSLY THAT THE WATER PUMPING CUSTOMER CLASSES HAVE UNIQUE USAGE AND INTERRUPTIBILITY CONSIDERATIONS THAT MUST BE ADDRESSED IN ANY NEVADA POWER MARGINAL COST OF SERVICE STUDY? Yes. In Nevada Powets last general rate case, Docket No. 01-10001, I testified on rate design on behalf of the water pumping classes for the Southern Nevada Water Authority. In that docket I pointed out that the marginal cost study and resulting water pumping classes' rates sponsored by Nevada Power were in error. They were in error because the Company's cost study ignored the usage characteristics of water pumping classes, instead. the cost study just assumed that these classes' costs were the same as "otherwise applicable classes." By usage characteristics, I mean the unique off-peak patterns of energy usage of water pumpers relative to other customer classes. DID THE COMMISSION AGREE IN THOSE PROCEEDINGS THAT THE MARGINAL COST STUDY AND WATER PUMPING CLASSES' RATES PROPOSED BY NEVADA POWER WERE IN ERROR? Yes. Ordenng paragraph 583 of the Commission order stated: "NPC's marginal cost of service study included separate base general rate energy related information for schedules LGS-WP and LGS-X-WP, but NPC did not use this information to develop separate rates. Due to curtailments, the rates proposed would be lower than that for otherwise applicable tariff." ::ODMA\I"COOS\HLRNODOS\369790\ I Page 3 of 12 e e DID THE COMMISSION REQUIRE NEVADA POWER TO BASE RATES TO THE WATER PUMPING CLASSES ON THE MARGINAL COSTS OF THESE CLASSES, RATHER THAN ON OTHER WISE APPLICABLE RATES? Yes. Ordering paragraph 585 of that same order stated: "The Commission finds that the proposal of the SNWA to base the schedule LGS-WP and LGS-X-WP classes' energy BTGRs upon the marginal cost study and not the classes' otherwise applicable rates is reasonable and approved." DO YOU HAVE SIMILAR ISSUES WITH RESPECT TO NEVADA POWER'S COST STUDY TREATMENT OF THE WATER PUMPING CLASSES' USAGE CHARACTERISTICS AND RESULTING MARGINAL COSTS AND CLASS RATES IN THE PRESENT PROCEEDINGS? Yes, as I explain below. DOES THE MARGINAL COST STUDY SPONSORED IN THE PRESENT PROCEEDINGS BY NEVADA POWER COMPLY WITH THE COMMISSION'S ORDER IN Docket No. 01-10001 WITH RESPECT TO WATER PUMPING CLASSES' MARGINAL COSTS? No, the marginal cost study filed does not comply with the Commission order in the last general rate case with respect to water pumping marginal costs. Nevada Powets deviations from the methods ordered in the last case result in its proposing rates in this case that are highly inequitable and discriminatory to the WP water pumping classes. ::ODMA\PCDOS\HLRNODOS\369790\1 Page 4 of 12 Q. 2 3 A. 4 5 6 7 8 9 10 11 12 Q. 13 14 A. 15 16 17 18 19 20 Q. 21 22 23 A. 24 25 26 27 28 e 'e DOES NEVADA POWER TESTIFY IN THE PRESENT CASE THAT ITS MARGINAL COST STUDY FOLLOWS PREVIOUS COMMISSION ORDERS? Yes. On page 3, lines 16-18 of Ms. Walsh's testimony she indicates: .....The marginal cost of service method utilzed for this case is primarily that used in previous cases, with a few enhancements and changes to comply with previous Commission orders... " The enhancements and changes made by Nevada Power to comply with previous orders later described in the testimony of Ms. Walsh do not go to the errors in the study with respect to the water pumping classes that I describe below. DOES MS. WALSH INDICATE THAT THERE ARE EXCEPTIONS TO HER USING OF INDIVIDUALLY IDENTIFIED MARGINAL COSTS IN HER STUDY? Yes. although she indicates that these exceptions "...are few and consistent with past practice and/or Commission orders..." (page 12. i. 14-15.) Unfortunately, the exception to using the available individual marginal transmission and distribution demand cost by Ms. Walsh is very costly to the water pumping classes. WHAT DO YOU MEAN BY YOUR STATEMENT THAT MS. WALSH MAKES AN EXCEPTION TO USING THE AVAILABLE INDIVIDUAL MARGINAL COST FOR WATER PUMPERS' TRANSMISSION AND DISTRIBUTION DEMAND COSTS? Ms. Walsh states on page 12, lines 20-22 of her testimony that .....Optional WP classes do have marginal cost individually calculated and values shown in Table 1 for the majority of their cost functions..." It is true that the majority of the WP or water pumping cost functions are calculated individually. But Ms. Walsh makes an important exception. similar to that which she made for the WP classes in the previous case by ::ODMA\PCDOCS\HLRNODOS\J69790\1 Page 5 of 12 2 3 4 5 6 7 8 9 io Q. 11 A. 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 e e using "otherwise applicable" classes' data instead of WP-specific data that were readily available elsewhere in her study. On page 12, lines 22-26 of her testimony, Ms. Walsh identifes what I consider to be her unnecessary and highly discriminatory data "substitution": u... The exception for WP is for the marginal cost of transmission and distribution costs for the non-optional class from which they came, re-scaled to the WP class sales... " (underlining added). PLEASE EXPLAIN. i express in my own words this same quotation from Ms. Walsh in a more specific, but equivalent way. Ms. Walsh had all the data for each WP water pumping class necessary to compute their respective marginal transmission and distribution demand costs, just as she possessed the equivalent data for the residential, general service and large general servce classes. For all these other classes that were not water pumping, she applied each of the respective class' time of use (Le. peak, mid, off and other) usage data appropriately to spread the transmission and distribution costs on the basis of each class' contribution to the particular time periods costs. That is, classes with relatively high on-peak usage, for example, receive relatively high allocation of the on-peak transmission and distribution costs, and so forth for the mid, off and other rating or usage periods. Although Ms. Walsh also had this same appropriate usage data for peak, mid, off and other time periods for all of the water pumping class schedules (LGS-2-WPS, LGS-2-WPP, LGS-2-WPT, LGS-3-WPS, LGS-3-WPP, LGS-3-WPT), she did not use these classes' data to spread transmission and distribution costs to the respective WP ::ODMA\PCDOLRNOOOS\369790\1 Page 6 of12 e e classes. Instead, she ignored these time of usage data and chose annual average numbers applied from the LGS classes. DOES MS. WALSH EXPLAIN WHY SHE CHOSE NOT TO USE THE AVAILABLE WP USAGE DATA TO DETERMINE WP MARGINAL COST OF TRANSMISSION AND DISTRIBUTION IN THE SAME FASHION AS SHE DID FOR ALL OTHER MAJOR CUSTOMER CLASSES? No. Without explanation, Ms. Walsh ignores all these available WP time period usage data and instead uscales" marginal transmission and distribution costs with an average annual WP usage scaling factor. That is, she added up all kwh energy sales for the year for a WP class, say LGS-2-WPS, and divided this annual sum by the total kwh energy sales for the year for what she calls an "otherwise applicable" class, or "non- optional" class, say LGS-2-S. The result of this gives nothing but an annual percentage of LGS-2-WPS sales to total LGS-2-S sales, which ignores all of the WP water pumping time period or time of usage characteristics. IS IT CORRECT TO ESTIMATE WP CLASS SHARES OF MARGINAL TRANSMISSION AND DISTRIBUTION DEMAND COSTS ON THE BASIS OF AVERAGE ANNUAL ENERGY CONSUMPTION? No. Marginal transmission and distribution costs are time sensitive. That is, usage during peak periods imposes a greater cost to Nevada Power's system than usage during off peak periods. Accordingly, customer class usage during peak periods results, or at least should result, in higher costs being spread to those classes with relatively more peak period usage. Customer class, rates should be developed ::ODMA\POOS\iILRNOOO\369790\1 Page 7 of 12 e e according to these usage periods to provide price signals to customers and, possibly to provide price incentives to shift usage to lower cost off peak periods. WHAT IS THE QUANTITATIVE EFFECT OF NEVADA POWER'S SPREADING OF MARGINAL TRANSMISSION AND DISTIBUTION DEMAND COSTS TO THE WP CLASSES ON THE BASIS OF ANNUAL AVERAGE, RATHER THAN ON THEIR RESPECTIVE PEAK, MID AND OFF PEAK USAGES? The effect is to over-allocate costs to the WP classes by $1,295,188 per year. This occurs because the water pumping classes usage characteristics, compared with most other customer classes, shift large amounts of power consumption to the lower cost mid and off peak time periods. These shifs to the lower cost periods are good for the transmission and distribution systems and for other customers' costs as well. Nevada , Power's marginal cost study ignores these benefits by removing the actual WP usage data and substituting instead an incorrect assumption that the water pumpers have the same average usage across all time periods. WHAT CHANGE TO NEVADA POWER'S FILED MARGINAL COST STUDY WOULD CORRECT THE PRESENT EXCESS ALLOCATION OF COSTS TO THE WATER PUMPING CLASSES? Nevada Power simply needs to follow the same method of using the water pumping usage data by time period for developing WP marginal costs as it has for every other major customer class in the study, and as it has done for all major customer classes, including the WP classes, in each and every marginal cost study filed previously since at least 1992. Nevada Power's proposed study discriminates against the WP classes by not allowing them to reduce costs by shifting usage to off peak periods. ::ODMA\PDOS\HLRNODOSI36979O1 Page 8 of 12 e e HAVE YOU MADE THE CHANGES TO NEVADA POWER'S MARGINAL COST STUDY THAT YOU RECOMMENDED IN THE QUESTION AND ANSWER IMMEDIATELY ABOVE? Yes. My three page Exhibit DEP-7 summarizes the changes to WP marginal transmission and distribution demand costs necessary to reflect the actual WP usage data. PLEASE EXPLAIN. Exhibit DEP-7 replicates a number of data series from Nevada Power's Certification marginal cost study. For easy reference, I include as Exhibit DEP-8 select pages from the Company's cost study in the Application which contains some of these data. At the top of each of the three pages of Exhibit DEP-7 I present the individual class usage data for all of the LGS, the LGS WP schedules, as well as the "Ratio of WP Kwh to LGS Kwh." WHAT DO THESE RATIOS SHOW? These show the ratios of WP to LGS usage for the peak, mid, off and other periods that should have been used by Nevada Power in spreading marginal transmission and distribution demand costs to water pumping classes. Also. shown is the total annual average WP usage that was incorrectly used in Nevada Power's study. For example, on page 1 of Exhibit DEP-7 the time differentiated WP ratio for Nevada Powets peak period is shown to be 1.34%, which Nevada Power should have used in order to be comparable to its treatment of all other customer classes. Instead, Nevada Power used the higher average annual kwh ratio of 1.84%, also shown on page 1 of Exhibit ::ODMA\PDOCS\HLRNOllOS\369790\1 Page 9 of 12 2 3 4 5 Q. 6 7 8 9 A. 10 11 12 13 14 15 16 17 Q. 18 A. 19 20 21 22 23 24 25 26 27 28 e e DEP-7 . To be consistent with other classes and with its past marginal cost studies, Nevada Power should have use the peak, mid, off and other time period ratios in place of its annual average ratio. DOES EXHIBIT DEP-7 CALCULATE THE WATER PUMPING MARGINAL COST OF TRANSMISSION AND DISTRIBUTION DEMAND BASED ON THE TIME DIFFERENTIATED WP USAGE DATA? Yes. Pagè 1 of the exhibit applies the WP time diferentiated usage data by rating period to marginal transmission costs in a manner consistent with Nevada Powets methods for other major rate classes. Page 1 at the bottom compares the total marginal transmission costs spread to the WP classes using the correct usage data by time period. As shown, Nevada Power allocates $798,911 in transmission costs to the WP classes, whereas the time period allocation should be $360,173. WHAT DO PAGES 2 AND 3 OF 3 OF EXHIBIT DEP-7 SHOW? Pages 2 and 3 of the exhibit correspond to page 1 but apply to distribution substation and non-revenue feeders, rather than the transmission cost shown on page 1. Page 2 computes WP marginal substation costs of $204,996 rather than Nevada Powets annual average calculation of $545,550. Page 3 computes WP marginal non-revenue feeder costs of $310,554 rather than Nevada Power's annual average calculation of $826,441. ::ODMA\POOS\HLRNOOOSU69790\1 Page 100f12 e e 1 Q. 2 3 4 5 6 7 8 WHAT IS THE TOTAL DIFFERENCE IN WP MARGINAL COST OF TRANSMISSION AND DISTRIBUTION DEMAND FROM CORRECTING NEVADA POWER'S STUDY TO REFLECT WP TIME OF USAGE? A. Page 3 of Exhibit DEP.7 indicates that Nevada Power's Study allocates excess costs to the WP classes of $1,295,188. The SNWA requests that the Commission. order Nevada Power to correct this inconsistent and harmful defect in its proposed study. PRESENT RATE SUBSIDY WHAT IS THE ISSUE WITH RESPECT TO THE RATE SUBSIDY DISCUSSED BY NEVADA POWER? Exhibit L1W-6 in Nevada Power's cost study calculates that the rates it proposes in this case result in the residential rate subsidy increasing by $23 millon per year over that decided in Docket No. 01.10001. The rate subsidy in Nevada Power's study is approximately $106 milion, whereas in the last general case it was approximately $83 milion. On pages 22.25 of Ms. Laura Walsh's testimony she addresses the sticky issue of how this subsidy might be reduced. She discusses the last Commission general rate case order wherein the Commission for a number of reasons decided to suspend movement of rates closer to costs in that case, but predicted revisiting the issue in this 2003 general rate case. Nevada Power's exhibits then offer alternative means of reducing the present subsidy. While the Company is to be commended for identifying alternative means, unfortunately its presentations result in rates for residential customers that arè higher than Nevada Power originally proposed. ;;ODMA\PDQS\HLRNODOSI36979CI\I Page 11 of 12 ~.e e DO YOU HAVE AN ALTERNATIVE PROPOSAL FOR REDUCING THE SUBSIDY THAT DOES NOT RESULT IN RESIDENTIAL RATES HIGHER THAN THOSE PROPOSED BY NEVADA POWER? Yes. My review of the cost of capital and other revenue requirement testimony in the first two phases of these procedings indicates that a number of parties are recommending significant downward adjustments to Nevada Power's requested increase in revenue requirement. To the extent that the Commission is persuaded to authorize revenue requirements below that sought by the Company, some level of these reductions could go first to reduce rates of customer classes that are currently paying the subsidy while not increasing residential rates. After some target reduction, say back to the level of the subsidy in the previous GRC, any remaining reduction should be shared in some fashion with the residential classes. I recommend this because the high level of subsidy is better to be reduced gradually so as to minimize any rate shock to residential customers DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? Yes. ::ODMA \PDOS\HLRNODOS\369790\ I Page 12 of12 e e Attachment 1 Page 1 of3 STATEMENT OF OCCUPATIONAL AND EDUCATIONAL HISTORY AND QUALIFICATIONS DENNIS E. PESEAU Dr. Peseau has conducted economic and financial studies for regulated industries for the past twenty-eight years. In 1972, he was employed by Southern Calìfornia Edison Company as Associate Economic Analyst. and later as Economic Analyst. His responsibilties included review of financial testimony, incremental cost studies, rate design, econometric estimation of demand elasticities and vanous areas in the field of energy and economic growth. Also. he was asked by Edison Elecrical Institute to study and evaluate several prominent energy models as part of the Ad Hoc Committee on Economic Growth and Energy Pncing. From 1974 to 1978. Dr. Peseau was employed by the Public Utilit Commissioner of Oregon as Senior Economist. There he conducted a number of economic and financial studies and prepared testimony pertaining to public utilties. In 1978 Dr. Peseau established the Northwest offce of Zinder Companies, Inc. He has since submitted testimony on economic and financial matters before state regulatory commissions in Alaska, California, Idaho, Maryland, Minnesota, Montana. Nevada. Washington. Wyoming. the District of Columbia. the Bonnevile Power Administration and the Public Utilties Board of Alberta on over one e e Attachment 1 Page 2 of3 hundred occasions. He has conducted marginal cost and rate design studies and prepared testimony on these matters in Alaska, California, Idaho, Maryland, Minnesota, Nevada, Oregon, Washington and in the District of Columbia. He has also conducted cost and rate studies regarding PURPA issues in the states of Alaska, California, Idaho, Montana, Nevada, New York, Washington, and Washington, D.C. Dr. Peseau holds the B.A., M.A. and Ph.D. degrees in economics. He has co-authored a book in the field of industrial organization entitled, Size. Profits and Executive Compensation in the Large Corporation, which devotes a chapter to regulated industries. Dr. Peseau has published articles in the following professional journals: Review of Economics and Statistics, Atlantic Economic Journal, Journal of Financial Management, and Journal of Regional Science. His articles have been read before the Econometric Society, the Western Economic Association, the Financial Management Association, the Regional Science Association and universities in the United Kingdom as well as in the United States. He has guest lectured on marginal costing methods in seminars in New Jersey and California for the Center of Professional Advancement. He has also guest lectured on cost of capital for the public utilty industry before the Pacifc Coast e e Attachment 1 Page 3 of3 Gas and Electric Association, and for the Executive Seminar at the Colgate Darden Graduate School of Business, University of Virginia. Dr. Peseau and his firm have participated with and been members ofthe American Economic Association, the American Financial Association, the Western Economic Association, the Atlantic Economic Association and the Financial Management Association. He was formerly a member of the Staff Subcommittee on Economics of the National Association of Regulatory Utilty Commissioners. Dr. Peseau has been President of Utility Resources. Inc. since 1985. Ne v a P o w C o y Ma r g i n a T r a n s m i s s i o n C o s t s Co m p a r i s o o f A n n u a l S c l i n g o f M a r g i n a l C o s t a n d T i m e o f U s e S c a l i n g Kw h U s a e Cl a s s Pe a k ' M i d Of f Ot h e r To t a l LG 5 - 2 S 21 9 . 7 4 5 , 1 2 7 21 1 . 6 4 1 . 1 4 3 33 8 . 5 0 6 . 1 3 4 1 . 2 5 3 , 0 1 2 . 4 7 2 2 . 0 2 2 , 9 0 , 8 7 6 LG S - 2 P 5, 7 5 0 , 3 7 7 5. 7 6 8 , 7 6 5 10 . 1 2 1 , 9 1 5 39 . 5 0 1 , 3 0 3 61 , 1 4 2 , 3 6 LG S . 2 T 52 9 . 7 1 8 52 9 . 2 8 2 1, 0 3 8 . 5 4 4, 6 1 9 , 7 3 4 6.7 1 7 , 2 8 2 LG S - 3 S 15 2 , 0 5 7 . 1 5 8 15 1 . 3 4 , 6 3 1 26 7 , 9 9 2 , 8 3 95 9 . 9 9 7 , 8 5 9 1 , 5 3 1 . 3 9 2 , 4 8 4 LG S . 3 P 11 5 . 7 4 9 . 9 3 9 11 6 , 3 6 8 , 2 6 2 20 8 , 9 1 5 . 8 0 2 75 9 . 7 0 4 , 8 1 3 1 . 1 9 8 . 7 3 8 , 8 1 6 LG S 3 T 12 , 4 5 3 . 6 1 0 12 . 1 1 1 . 9 9 1 25 , 6 6 9 . 0 4 7 10 0 . 1 4 5 . 6 9 15 0 . 3 8 . 3 4 2 To t a l L G S 50 6 . 2 8 5 , 9 2 9 49 7 . 7 6 4 , 0 7 4 85 0 , 2 4 4 . 2 8 2 3 , 1 1 6 , 9 8 1 , 8 7 5 4 , 9 7 1 . 2 7 6 . 1 6 0 LG S . 2 S . 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I " S4 U 3 I S 3 U t s S 2 : i o . 1 2 ." . 4 ' s o s o Ex h i b i t D E P 8 Pa g e 1 o f 4 i. " T i . n l m AI _ J : ;1 . 1 1 , m. l ' U 1 ' ''' . . 1 3 7 S2 7 8 , St U O U l 2 $7 , 8 . 3 12 1 0 . 1 8 11 1 . 2 15 . 8 1 . . 13 . " . 3 l4 1 1 t ØI . i n I2 . 0 4 U o t IZ f 4 1 1 . 3 11 4 3 . " 7 11 1 . 7 5 15 . 4 5 "" . 1 2 1 12 4 2 . 4 3 12 2 0 , 3 5 N8 Y . " - C o 1 Do e l N o . 0 3 . 1 0 0 1 Ei l U W . 2 ~ E R f ~t o l 5 ' $1 0 1 . 7 1 1 SO so SI , 1 9 4 11 1 4 S: s $5 u n 17 1 12 1 1 lõ , í S , l ' O O St U l l SL O 12 2 . lS M l 0 7 0 un . 3 5 . . 4 0 11 , 0 1 1 . 3 2 7 It U I I I , 1 2 9 11 7 . 3 7 3 . 1 1 SA 2 . . . 2 . M f 11 . ' . . _ .1 . 1 5 3 12 . . . 8 . 1 1 $2 1 . 1 1 . 2 7 S2 . z , 1 7 3 13 2 1 , ' " S1 U l l . . S 1 si 5 , 1 0 U n II I 3 : It 3 U 3 5 11 , 0 7 4 11 1 , 0 4 12 l . 1 3 l1 . S 3 S2 , I 5 10 SO II U 4 U 8 4 $3 z . n . m SU I U 4 5 12 l , 4 7 , 2 11 5 1 . 3 3 0 . " S'G O . S 3 l . 3 G S2 , S O . 7 3 l 13 0 . 0 1 1 SU . I I U l l $5 7 . 7 5 . 1 3 1" ' 1 0 . 5 5 $8 7 1 . 3 ' S2 I . 5 5 U I . s: . 7 1 z . . . Sl . 7 1 7 . : 5 $2 I U I I 11 7 . 0 5 7 12 . 1 . . . . Z 5 13 . 4 3 . 1 1 7 3 '3 . 1 2 . 1 0 1 St . 1 7 5 . 1 5 0 ss . o . SI 6 8 , 6 7 To i M i Q l "- e ( ' " S2 1 4 . 4 & 1 4 l $7 1 1 . 0 0 . " 7 SU 7 2 . 4 1 ' St U l 7 . o 0 1 S3 , 1 n . o t S 'n r . m . c o i S4 . n s . n i S7 1 U I 5 11 2 5 . 1 2 4 . H 4 '" . 1 9 4 . 1 7 0 S1 G , U H ". 3 . m $4 7 . 1 1 0 . 0 2 7 15 5 . 1 5 . 0 2 5 S3 . f 7 U : i 1 S4 1 7 . ' " 11 2 U l l I 13 . o z . . , , 14 , 4 5 2 . 1 4 ' 14 . 0 2 u i n Sl . 1 4 5 . 7 2 I S1 1 1 2 , 7 " 15 0 , ( 1 3 1 ~. i ' . . o o $ 9 1 , . s o 5 , 7 4 ~ l í 3 , j : l . 1 n s_ In 1 1 T . ~ 3 : M i i " l y . . r v a l C u l o ' l l F . c I l I C o " ( p p 3 1 . m o f a l l e . _ I p e i c u l l . , . T a l l i e 2 : A A n u a i i i . d S a l e i I l C l I a " 1 1 1 1 1 ' - C l Q . ( P l l i Z ~ n u m r 0 1 e u i l o . . Ir Q ) T i i i 3 : M o l i M a r g i l C I I l F d V . . C o l l ( p o e 3 ) . m l C V C O t s p e 0 J . T . . 3 : " ' . . I y . . a i C u i e r e n F I I C o s l s I P 3 ~ _ e r 0 1 C U S L _ , (n : ! ) T l l I : M I l I l D e " - a s N o R _ F ø . T . l i 7 : ~ a l O e " - S u l l T " " ' : M a I O t d A I y _ T i a n l ø . . . e t . l i i a o n ' . 7 . 1 $ 1 . 1M ) T a b ' " 1 0 : . . " " G e R l _ ( p a l l ~ O ) . _ 0 ' " 1 l 0 \ l i p . i " in s ) W o r a i t : M . e i i i l ! C o i i ' C o t l P a ( ø . t : ) . " ' * 2 : A M e d s a . . i i C u s _ . ' r I ~ C i a . . ( p . 2 ~ ln i ) T e t i 3 : " " ' ' . . C u i i F a c C O t s ( P 1 9 ' 3 1 , c i i n f a . C O . 1 2 f o L O . 3 T . L G S . X S . L G S . X P , L G S - x . L G s . . W P T . L G S . 3 - W f . a l l S L . 12 2 . 1 0 7 . ' " 70 1 . . r g l "e . _ . ' " U3 3 i 4 40 2 0 " 02 2 " 3. 5 " ' 1l 0 1 ' 1 _ US 0. 2 1 0, 0 4 " U1 % 41 1 e i 4 05 8 ' " D.O l % 2, 5 1 ' l 2, 5 ' " 0, " ' " O,D 3 % 0. 0 1 ' l 0,1 1 1 1 1 0, 2 4 " US " 0. 4 1 % 0. 0 1 % \) . 1 3 % l0 0 ~ ' Ex h i b i t D E P B ,. . 2 o f 4 ... . . _ . . Pa g e Nt P O W c o p a n y ... . Oo i l N o . 0 3 1 0 0 1 Ex U W - 2 - C R T Pa g 20 1 5 3 T_ 2 : A n 1 l l i S l I l l i d C u I I I I n i l . C I . . Fl c f l : No C u O l I I ( n I l . ( f o X C I Ma u m D e m a n d O n D e a n M i d D e m i n c : En e r g : O n En r g : MI En : O I J En e r : O t r En : T o I Un N o . CI ml t l b i a i C U O l I l ) WI (" ' ) Pe l ( ( n ' i Pe ( n I l Ol ( n l ) P, i i ( 1 1 2 1 PN k ( n 2 ) Pe k ( r i ) (1 1 ) kW h lin No , II RS M U I F l l l l 2. 0 i . 9 0 4 29 1 . 5 5 . 1 0 2S 8 . 7 9 7 M 1 35 , 8 9 , G 2 11 4 7 . 7 S . 7 8 8 1. 5 1 . 0 0 9 . 8 0 II 10 AS 4. 8 0 9 . l s a 1, 1 . 0 . 8 8 . 5 8 5 1I . 3 1 3 M 1 I 1, Q 0 0 7 . 8 8 2. . 2 2 0 . 4 2 8 1I . 8 2 4 . 2 . 7 4 3 10 11 RS 4, 8 8 1 1I . 1 l 2 4 8 4 5. 0 3 8 . 0 4 8, 3 2O . 8 O , 8 38 . 4 0 , 8 1 7 11 12 OS 87 7 . 1 2 17 . 8 4 7 . 7 1 7 eU 3 4 . _ 10 4 . 0 1 S . m .. 8 I 1 M S I . 59 0 . 1 5 2 . 3 5 12 13 LO S I 21 . 0 2 4 8. 5 1 1 8 . 1 2 l 38 , 2 8 1 1 1 .4 . 2 1 3 . 1 7 2 lS . 1 8 l . 8 2 8 U2 9 , 3 1 , 8 7 3. 1 2 3 . 1 . 4 . 7 2 8 13 14 LG S 12 , 8, 2 1 ~ I 5 3 t, 1 4 . o 4 9 1. 7 8 $ . 5 9 3, 1 2 7 , 8 3 21 1 1 . 7 4 5 . 1 2 7 21 t , 8 1 . 1 4 3 _e o l 3 4 1, 2 0 1 2 , 7 2 2. o 2 2 . 8 Q , 8 7 8 14 1S LG S P 28 . 17 5 . 3 .5 , 7 8 2 .. . 4 8 3 12 , 4 5 5, 7 S . 3 S. 7 U 7 Q 10 . 1 2 1 . " 5 38 . 0 1 . 0 3 81 . 1 4 2 , 0 0 15 - t. LG S o 2 T 12 13 . 3 1 1 1 3. 1 0 a 3. 1 8 7 7. 8 7 1 52 8 . 1 8 12 . 2 1. 0 3 8 . 6 8 "" ' 1 1 . 7 3 l. 1 7 . 2 8 2 18 17 LG S 2, 4 0 8 3. 4 4 . 8 2 8 1. 0 7 4 . 1 4 2 1.1 1 1 . 7 2 8 1. 1 1 7 1 . i 3 O 15 2 , 0 5 7 . 5 8 15 1 . 3 4 4 . l J 1 28 7 . l i 2 , 8 8 11 . 1 1 1 1 7 , 8 s t 1. 5 3 1 . 3 9 . ' 8 4 17 18 l. 80 0 3, 1 2 0 . 4 7 1 "" ' 8 7 85 0 . 8 7 2 1. 5 1 0 11 8 . 7 4 1 1 , 8 11 8 , 3 8 , 8 2 20 . 8 1 5 . 8 0 2 75 0 . 7 0 4 , 1 3 '. 1 8 8 . 7 3 8 1 8 18 11 LG S o 10 8 .1 8 , 1 1 7 HU M 12 0 . 1 1 7 8 25 ' ' ' ' 5 3 12 , i 5 . 8 1 0 12 . 1 t 1 . 1 25 . 8 8 . 0 4 7 10 0 . 1 4 5 . 6 9 4 15 0 . 3 . 3 2 18 20 LG S - X S 88 45 . 8 3 13 . 1 8 7 13 . 1 9 8 25 . 4 0 9 1. 4 3 . 4 7 8 1. 8 8 C M 0 4 2, 8 0 . 5 8 8 11 . 5 8 7 . 0 1 1 9 17 . 1 8 1 . 2 1 8 20 21 LG X P 25 2 1I 8 48 1. 7 0 . 1 4 8 39 . 3 1 7 40 2 . 5 1 8 72 1 . 3 8 80 . 1 3 0 . 5 7 5 SU 5 2 , H 10 3 , 8 5 1 . 8 4 8 38 7 . " 5 . 1 8 7 81 1 . 5 2 . 8 0 21 22 LO S - X T I" 12 48 na 45 4 , 3 6 8 ." . 8 1 8 80 7 , 8 8 12 . 3 8 . 10 . 8 8 . 0 7 0 14 1 . 1 7 8 . 5 2 47 1 . 1 0 , 1 4 3 77 5 . 7 1 5 . 7 1 1 22 23 lG S . 2 - W P S 43 2 2. 8 . 6 0 0 11 5 . . 2, 5 4 , 5 8 1 4. 5 1 3 . 2 1 4 18 . 1 1 . . . . 2 8 11 . 5 7 3 . 3 4 5 31 , 2 2 0 , 5 8 23 24 lO S I . W P P 48 1S . 4 8 1 80 2 . . 81 0 , 1 2 7 5" . 8 3 1. 0 5 1 1 . 1 9 3.1 8 0 . 7 5 0 5. 4 3 3 . 5 7 8 24 25 lO S - I . W P T 12 1U 8 2 5 - . 72 . 1 1 2 17 7 . 3 47 1 , 1 0 8 96 1. 8 3 . " 7 25 21 LG S . W P S 13 2 20 8 , 3 2 73 5 . . 53 1 . 4 0 8 4. 2 ' 7 , 1 2 2 17 . 1 3 5 . a 28 . 2 . 8 0 1 .8 . 2 8 . 5 0 7 26 27 lG S . W P P 12 0 31 7 . 2 4 7 1. 2 1 8 . . 1, 0 7 U S O I I 3, 5 8 0 . 0 8 5 22 . 8 1 1 . 7 1 7 45 . 1 1 8 . 7 1 7 73 . 1 1 8 . 1 8 5 27 2a lG S - a - W P T 48 23 . 8 5 8 7. 4 8 9 . . 4. 0 8 . 7 7 1 8, 1 7 . 9 0 18 . 3 1 . 8 1 51 , 8 3 . 3 4 81 . 1 7 . _ 28 28 LO S - X . \ Y 29 30 LG S . X . W P P :i 31 LG S . W P T 31 32 SS S 32 33 SS P 33 34 SS T 12 0 50 3 , 0 1 2 11 . 8 1 5 19 , 0 1 3 10 , 1 1 7 48 5 . 2 0 0 23 5 . 0 5 4 2. 9 0 . 1 5 1 6, 9 5 7 . 4 1 10 . 5 8 3 , 5 5 34 35 SL ( n 3 ) lI l f m e t 8 l 11 . 0 1 8 78 . 4 4 8 1. 7 1 3 , 9 7 3 11 , 8 6 8 . 2 6 8 2D . 8 8 . 0 2 11 5 . 1 8 1 , 0 2 6 15 5 . 3 0 . 1 6 35 38 RS o P e l 16 , 0 4 4 33 7I ~ 7 7 29 , _ 11 5 0 , 2 5 1 1. 3 2 5 . 1 7 0 38 37 Gl i e l 3l l 0 4 83 22 4 , 4 8 0 84 3 . 8 " 2. 8 8 . 7 6 4 3. 7 4 8 . 2 3 5 37 38 AM P 38 3D OR S F 32 8 30 . 1 7 0 . 39 . 4 0 9 10 1 , 5 2 7 17 1 . 1 0 8 39 e 40 OR S 3,1 3 3 55 1 0 8 - 1, 2 2 , 0 4 0 11 . 8 5 4 , 5 1 6 13 . 6 3 5 . 6 8 . 40 41 OR S . L . 41 42 OG S 12 0 3, 6 4 5 . 74 . 2 6 12 , 1 0 2 SO . 0 1 1 42 43 OL l - 43 44 44 45 TO T A l 8. 3 . 1 26 , 7 5 7 . 1 2 5 4. 6 5 9 . 1 3 1 4, 7 9 8 , 4 3 4 8.8 0 2 , 8 3 1 l 2. 5 5 . 0 9 8 , 0 0 2 2. 2 6 , 7 0 4 3 . 4 7 2 3 " 0 4 . 3 8 1 . 6 3 9, 7 2 . 6 9 3 , 5 0 7 1e . 3 7 . 8 9 6 . 3 3 4 45 So : (n 1 ) s i a l i i i i t J . 1n 2 ) S l l e m e n l J f o r i l l e 1 a s e l B l t c e f t i * 1 F a m i l . R S . R S r g . G S , l O S - I , s t R S _ P A I . a n d G S _ P A I T o t " W h f o I h e a d a s s e s a r e s p a d p r l l t o ' 1 m B o f u s e u s i n h o l y c l s s I o $ . (n 3 ) M e t r e c u i o . . i a t h " u r b a o f m e t . a s u l n o n m i t e r p e r l e c . Ex h i b i t D E P 8 . . . Pa g e 3 o f 4 Ne v a d a P o w e r C o m p a Do e t N o . 0 3 - 1 0 0 1 Ex U W - 2 - e R T Pi i . 8 0 f 5 3 Ta b l 8 : M I D e m a n R e n u : T r a n i m " Un N o Cl i i On MI Of OI e r To t a 9 RS F e m l 8. 7 1 4 . 0 4 1 98 . 9 6 4 23 0 38 . 8 9 5 t. m . 9 3 8 10 AS 35 . 8 8 0 . 7 7 4 3. 6 4 8 . 8 5 75 5 15 2 . 2 8 39 . 7 8 . 8 1 8 11 RS o l 16 8 . 1 9 1 19 . 2 1 1 Ii 72 9 18 8 . 1 3 7 12 GS 2. 2 9 9 . 8 3 8 26 8 9 9 7 78 19 . 7 2 2. 7 8 4 3 7 13 LG B - 1 12 . 2 9 3 . 9 8 1. 4 0 7 , 2 39 10 8 . 0 7 13 , 8 0 . 2 6 14 LG S . 2 S 8. 3 9 . 3 3 0 81 2 . 9 2 0 24 1 70 . 8 9 9 7. 8 2 3 . 3 9 0 15 LG B - 2 P 18 8 . 8 8 22 . 3 9 1 7 1. 9 2 4 21 0 . 9 8 4 18 LG S . 2 T 15 . 2 7 1 1. 2 0 1 17 3 17 . 6 4 17 LG S - 3 4. 7 4 7 . 7 5 8 66 9 , 5 2 0 17 5 48 , 8 8 5 5. 6 8 . 3 3 8 e 18 LG S 3 P 3, 5 1 1 . 1 7 5 42 0 . 2 5 . 12 1 1 35 . 0 0 3. 9 6 3 3 0 19 LG S - 3 T 38 0 , 0 0 5 42 . 1 8 1 16 3. 7 2 9 40 5 . 9 1 1 20 LG S X S 53 . 4 5 9 6, 1 9 2 55 3 60 . 2 3 3 21 LG B - X P 1. 8 1 6 . 8 9 5 21 4 . t l 3 G5 11 1 8 5 2. 4 9 . 0 9 22 LO S . X l 2. 4 3 6 , 8 1 28 6 . 9 1 3 87 22 , 0 4 8 2. 7 4 8 . 3 0 7 Z3 LG S . W P S 12 7 . 6 1 1 1 14 . 9 5 7 4 U0 5 14 3 9 4 7 24 lG S . 2 . W P P 18 , 8 8 1. 9 9 0 1 17 1 18 . 5 0 25 LG S . 2 . W P T 5. 1 7 2 62 0 0 53 5. 4 5 28 LG S 3 - W P S 14 9 . 3 1 17 . 9 4 9 6 1.5 4 1 16 9 . 1 2 6 27 LG S . a - W P P 21 4 . 6 1 0 25 . 8 7 3 a 2. 1 3 9 24 2 , 4 3 0 28 LG S W P T 19 5 , 9 0 22 , 8 2 9 2. 0 2 4 22 . 3 0 29 lG B - X . W P S 30 LG 8 - X . W P P 31 lG S . X . W P T 32 BS S 33 SS P 34 SS T 35 SL 48 , 7 3 8 12 . 5 5 6 10 87 3 81 . 7 6 38 RS a l 0 79 0 0 .8 0 37 GS P a l 0 22 8 0 0 22 8 38 Al P 39 OR S - M e 40 OR a 41 OR S o l 42 OO S 43 Ol O S . 1 44 4S TO T A l !1 l ; 4 1 . 7 7 3 -- 1 2 . 7 5 8 2. 2 1 - 52 7 ; 8 8 7 - 8 9 . 4 4 , 6 3 8 sr ~ . i U n o . C o 89 . 8 4 . 6 3 1. 0 ~ 0 SO : a Ta b l 9 : C o m p u t a t i o n 0 1 A n n u a l M a r g I n a l U n l l C o s D e m a n R e l a t d ( p a g e 9 ) , f o r t r s m i s s i w I I t i l o s s s x Wo r p a r 3 : L o a d W e l g h P r b i i t o f P e a k ( p a g e 2 1 ) · r n g l 1 c t o r ( p a g 2 f ) . x Ta b 2 : A n a l e d s a . . 8 I C u m e r s b y r a C l ( p e g l 2 ) . Ex h i b i t D E P 8 Pa g e 4 o f 4 NM d P o w C o Do t N o 0 3 1 0 0 1 Ei U W - 2 - e Pa g e 8 of 53 Ti l 8 : i i D e i i n d R I l N o I M u . F e e Un N o Cl n on MI d Of Ol 10 1 1 I RS F 8 1 l 12 . 8 W . 2 1. 8 8 . 7 3 7 33 ' 55 , 1 l 8 8 '' ' . 0 7 2 0 0 9 10 AS 51 . 1 8 2 , 0 5, 2 1 , 2 9 0 1. 0 8 7 21 9 . 0 8 0 57 , 2 3 , 5 . " RS %4 2 , 0 5 27 . 8 4 8 8 1. 0 4 2'0 . 7 " 12 OS 3, u t . S l 37 7 3 11 0 28 , 3 8 8 3, 7 1 0 . 7 8 13 LO S . l 17 . 8 9 2 . 8 8 2. 0 2 , 2 1 2 57 1 15 3 , 5 9 11 . 8 7 2 . 2 14 LQ S ", 8 U 0 4 '. 1 8 9 . 1 2 34 7 10 2 0 3 4 lt a . I 0 7 15 LG S Je U 3 32 , . 10 2. 7 6 30 3 & 4 18 l. G $ U e 17 LG S 8. 3 2 7 8 1 81 9 . 1 1 0 25 2 70 . 3 5 7. 7 2 . 0 1 8 18 LG S 5. 0 5 . 1 4 1 80 4 . . 18 5 tI . m 5, 7 0 8 . 1 8 2 19 LG S o 20 l. o X ( n l ) 38 . 4 . .. . . . 1 5 1 39 8 43 , 3 4 2 21 l. G S ( n t ) 1, 3 , 4 0 1 15 4 3 9 47 13 . 1 5 8 1, 4 7 5 , 0 0 1 22 LO S X T 23 LQ S 18 3 . 7 5 21 . 5 2 l 1,8 7 7 20 . 1 1 1 Z4 LG N o W P P 23 , 8 1 3 2. 8 8 4 1 24 8 28 , 8 4 25 LG N . W P T Z8 LG $ P S 21 5 , 3 3 25 8 3 2 8 2, 1 7 24 3 . 0 0 27 LC J P 30 . e a 38 , 9 " 7 11 3. 0 7 9 34 8 , 9 5 28 LG 9 - W P T 29 LG S . X . W P S 30 LG S o W P P 31 LG S x . P T 32 SS S 33 SS P 34 SS 35 8L 70 . ' 4 1 18 . 0 1 0 14 11 8 80 . 1 0 4 38 RS . . ' 0 1l 4 0 0 11 4 37 GS 0 32 0 , 32 38 Ar N P 39 OR s - F e 40 OR S 41 OR S 42 OO 43 OL G S t 44 45 TO A L 10 U 4 3 8 1'. V 5 8 . 4 9 5 2, 8 8 70 5 , 2 4 8 '~ 7 . 7 3 9 Dl S l i ' " " l I l l l A D e C O . .1 õ f 3 9 1. ~ ~ o 0 So. Ti b l . 9 : C o P U U o n o f A n l l f o l U n i C o i l : P t m R i l i t e ( p . g e 9 ) , f o n o n u f i l ' l o s x Wo t p i 3 : L Ø d W . / g P i b l l l l y o f ' e i l l ( p e 2 ' ) · ~ f a ( 1 I 2 1 ) . x Ti d 2 : M u S I l i ~ t l m e Q e ( P I 2 ) - (n l ) AI o f c o f o l G S e n d L G S - X ø n d e s l l b y 5 0 t o r e t i c u s t s p d 1 s l i .'"e e AFFIRMATION I, Dennis E. Peseau. pursuant to NAC 703.710 hereby affirm that the foregoing prepared testimony was prepared by me or under my direction and is correct to the best of my knowledge. S'J-.~ ,¡;¿U~ Da1 J?# ,,e It BEFORE THE PUBLIC UTILITIES COMMSSION OF NEVADA Application of NEVADA POWER COMPAN for authority to increase its annual revenue requirement for genera rates chaged to all classes of electric customers and for properly related thereto. Application of NEVADA POWER COMPANY for approval Of new and revised depreciation and amortzation rates. DENNIS E. PESEAU TESTIMONY Phase Three - Rate Design Work Papers ) ) ) ) ) ) ) ) Docket No. 03-10001 Docket No. 03-10002 Ne v a d a P o w e r C o m p a n y Ma r g i n a l T r a n s m i s s i o n C o t s Co m p a r i s o n o f A n n u a l S c a l i n 9 o f M a r g i n a l C o s t a n d T i m e o f U s e S c a l i n g Kw h U s a Cl a s s Pe a k Mi d Of Ot h e r To t a l LG S - 2 S 21 9 , 7 4 5 , 1 2 7 21 1 . 6 4 1 . 1 4 3 33 , 5 0 . 1 3 4 1 , 2 5 3 , 0 1 2 , 4 7 2 2 , 0 2 2 , 9 0 4 , 8 7 6 lG S - 2 P 5, 7 5 0 , 3 7 7 5, 7 6 8 . 7 6 5 10 , 1 2 1 . 9 1 5 39 , 5 0 1 . 3 0 3 61 , 1 4 2 . 3 6 lG S - 2 T 52 . 7 1 8 52 9 , 2 8 2 1, 0 3 8 , 5 4 4, 6 1 9 , 7 3 4 6, 7 1 7 . 2 8 2 lG S - 3 S 15 2 , 0 5 7 , 1 5 8 15 1 , 3 4 4 , 6 3 1 26 7 , 9 9 2 , 8 3 6 95 9 , 9 9 7 , 8 5 9 1 . 5 3 1 , 3 9 2 . 4 8 LG S - 3 P 11 5 , 7 4 9 , 9 3 9 11 6 . 3 6 8 . 2 6 2 20 6 . 9 1 5 . 8 0 2 75 9 . 7 0 4 . 8 1 3 1 . 1 9 8 , 7 3 8 . 8 1 6 LG S - 3 T 12 . 4 5 3 . 6 1 0 12 . 1 1 1 , 9 9 1 25 , 6 6 9 . 0 4 7 10 0 , 1 4 5 . 6 9 4 15 0 , 3 8 . 3 4 TO l l l G S 50 6 . 2 8 5 , 9 2 9 49 7 , 7 6 4 . 0 7 4 85 0 , 2 4 4 . 2 8 2 3 , 1 1 6 , 9 8 1 , 8 7 5 4 . 9 7 1 , 2 7 6 , 1 6 0 LG S . 2 S - W P 2, 9 5 4 , 5 8 1 4.5 1 3 , 2 1 4 18 , 1 7 9 , 4 2 6 11 , 5 7 3 . 3 4 5 37 , 2 2 0 . 5 6 6 lG S . 2 P - W P 61 9 , 1 2 7 59 6 , 9 3 2 1, 0 5 6 , 7 6 9 3, 1 6 0 , 7 5 0 5. 4 3 3 , 5 7 8 LG S - 2 T - W P 72 . 1 7 2 17 7 . 3 2 7 47 9 . 1 0 8 96 , 3 6 1. 6 9 3 , 9 6 7 LG S - 3 S - W P 53 1 . 4 0 4, 2 9 7 , 1 2 2 17 , 1 3 5 , 2 6 8 26 , 2 9 9 , 8 0 1 48 , 2 6 3 . 5 9 7 LG S . 3 P . W P 1, 0 7 8 , 6 0 6 3, 5 9 0 , 0 6 5 22 , 9 6 3 . 7 1 7 45 , 6 3 6 , 7 9 7 73 , 2 6 9 , 1 8 5 lG s T . W P 4. 0 8 . 7 7 1 6, 2 1 7 . 4 9 0 19 , 5 3 1 , 7 6 1 51 , 7 8 3 . 6 3 4 81 , 6 1 7 , 6 5 To t a l W P 9,3 4 0 , 6 6 3 19 , 3 9 2 . 1 5 0 79 , 3 4 . 0 4 9 13 9 , 4 1 9 , 6 8 7 24 7 . 4 9 8 . 5 4 9 LG S M a r g i n a l T r a n s m i s s i o n C o s t s Cl a s s Pe a k Mi d Of Ot h e r TO l I LG S - 2 S 6, 9 3 9 , 3 3 0 81 2 . 9 2 0 24 1 70 , 8 9 9 7. 8 2 3 , 3 9 0 LG S . 2 P 18 6 , 6 6 2 22 . 3 9 1 7 1, 9 2 4 21 0 . 9 8 LG S - 2 T 15 , 2 7 1 1. 8 2 0 1 17 3 17 . 2 6 5 LG S - 3 S 4, 7 4 7 , 7 5 8 56 9 . 5 2 17 5 48 , 8 8 5 5. 3 6 6 , 3 3 8 LG S . 3 P 3, 5 1 1 . 1 7 5 42 0 , 0 2 5 12 8 35 , 0 0 2 3, 9 6 6 , 3 3 0 LG S . 3 T 36 . 0 0 5 42 . 1 6 1 16 3, 7 2 9 40 5 , 9 1 1 To t a l 17 . 7 9 0 , 2 1 8 WP M a r g i n a l T r a n s m i s s i a n C o s t U s i n g A n n u a l K W h S c a l i n g Cl a s s Pe a k Mi d Of f Ot h e r To t a l LG S - 2 S - W P 12 1 . ß ß l 14 , 9 5 7 4 1. 3 0 14 3 , 9 4 7 lG S - 2 P . W P 16 . 5 8 8 1. 9 9 1 17 1 18 , 7 5 0 lG S - 2 T . W P 3.8 5 1 45 9 0 44 4. 3 5 lG S . 3 S . W P 14 9 . 6 3 1 17 , 9 4 6 1.5 4 1 16 9 . 1 2 6 LG S - 3 P . W P 21 4 , 6 1 0 25 , 6 7 3 8 2. 1 3 9 24 2 , 4 3 0 LG S - 3 T . W P 19 5 , 3 9 0 22 , 8 8 3 9 2. 0 2 4 22 0 , 3 0 To l a l 79 8 , 9 1 1 Co P e r i R a t i o o f W P K w h t o L G S k w h Pe a k M i d O f f O t h r 1, 3 4 % 2 . 1 3 % 5 , 3 7 % 0 . 9 2 % 10 , 7 7 % 1 0 . 3 5 % 1 0 . 4 4 % 8 . 0 0 % 13 . 2 % 3 3 . 5 0 % 4 6 , 1 3 % 2 0 . 9 0 % 0. 3 5 % 2 . 8 4 % 6 . 3 9 % 2 . 7 4 % 0. 9 3 % 3 . 0 9 % 1 1 . 1 0 % 6 . 0 1 % 32 . 8 0 % 5 1 . 3 3 7 6 . 0 9 5 1 . 7 1 % 1, 8 4 % 3 . 9 0 9 , 3 3 % 4 , 4 7 % NP C An n u a l Av e r a g e 1. 8 4 % 8. 8 9 % 25 , 2 2 % 3. 1 5 % 6. 1 1 % 54 . 2 7 % 4: WP M a r g i n a l T r a n m s i s s i o n C o i U s i n g n m e o f U s e K w h S c a l i n g Pe a k M i d O f f O t h r T o t a l 93 . 3 0 3 1 7 . 3 3 5 1 3 6 5 5 1 1 1 . 3 0 20 , 0 9 7 2 , 3 1 7 1 1 5 4 2 2 , 5 6 9 2. 0 8 1 6 1 0 0 3 6 2 . 7 2 7 16 , 5 9 2 1 6 , 1 7 0 1 1 1 , 3 3 9 3 4 , 1 1 3 32 , 7 1 9 1 2 , 9 5 8 1 4 2 . 1 0 3 4 7 , 7 9 4 11 8 , 0 8 1 2 1 . 6 4 3 1 2 1 , 9 2 8 1 4 1 , 6 6 4 36 0 , 1 7 3 Pe r c e n t Di f e r n c e 29 . 3 3 . 1 0 .1 6 . 9 2 % 59 . 6 6 % 39 5 , 7 8 % 40 7 . 2 4 %~12 1 , 8 1 % Ex h i b i t D E P . 1 Pa g e 1 o f 3 e $ Di e r e n c e ': 1 3, 8 1 9 -1 , 6 2 7 -1 3 5 . 0 1 3 -1 9 4 , 6 3 6 -7 8 . 6 4 0 :: e Cl a s s LG S - 2 S LG 5 - 2 P LG S - 2 T LG 5 - 3 S LG S - 3 P LG S T To t a l l G S LG S , 2 8 - W P LG 8 - 2 P . W P LG S . 2 T . W P LG S . 3 S - W P LG S - 3 P - W P LG S o 3 T . W P To t a l W P Pe a k 21 9 . 7 4 5 . 1 2 7 5. 7 5 0 . 3 7 7 52 9 . 7 1 8 15 2 , 0 5 7 . 1 5 8 11 5 . 7 4 9 . 9 3 9 12 . 4 5 3 . 6 1 0 50 6 . 2 8 5 . 9 2 9 2, 9 5 4 . 5 8 1 61 9 . 1 2 7 72 . 1 7 2 53 1 . 4 0 6 1. 0 7 8 , 6 0 4. 0 8 . 7 7 1 9. 3 4 0 , 6 6 3 Mi d 21 1 . 6 4 1 . 1 4 3 5. 7 6 8 . 7 6 5 52 9 , 2 8 2 15 1 . 3 4 4 . 6 3 1 11 6 . 3 6 8 , 2 6 2 12 . 1 1 1 . 9 9 1 49 7 . 7 6 4 , 0 7 4 4, 5 1 3 . 2 1 4 59 6 . 9 3 2 17 7 . 3 2 7 4. 2 9 7 . 1 2 2 3. 5 9 0 . 0 6 5 6. 2 1 7 . 4 9 0 19 . 3 9 2 . 1 5 0 Ne v a d a P o w e r C o p a n y Ma r g i n a l S u b $ t a U o n C o t s CO O l W ~ Ñ m a \ ~ ~ t l t \ a l C I \ a M T ' i m o f ' J ~ s e i n Kw h U s a g e Of O t h e r T o t a l 33 8 . 5 0 . 1 3 4 1 . 2 5 3 . 1 2 , 4 7 2 2 . 0 2 2 . 9 0 4 . 8 7 6 10 . 1 2 1 . 9 1 5 3 9 , 5 0 1 . 3 0 3 6 1 . 1 4 2 . 3 6 0 1. 0 3 8 . 5 4 8 4 . 6 1 9 . 7 3 4 6 , 7 1 7 , 2 8 2 26 7 . 9 9 , 8 3 6 9 5 9 . 9 9 7 , 8 5 9 1 . 5 3 1 . 3 9 2 , 4 8 4 20 . 9 1 5 . 8 0 2 7 5 9 . 7 0 4 . 8 1 3 1 . 1 9 8 . 7 3 8 . 8 1 6 25 . 6 6 9 . 0 4 7 1 0 0 , 1 4 5 , 9 4 1 5 0 . 3 8 . 3 4 2 85 0 . 2 4 4 . 2 8 2 3 . 1 1 6 . 9 8 1 . 8 7 5 4 , 9 7 1 . 2 7 6 . 1 6 0 18 . 1 7 9 . 4 2 6 1. 0 5 6 . 7 6 9 47 9 . 1 0 8 17 , 1 3 5 . 2 6 8 22 , 9 6 . 7 1 7 19 . 5 3 1 , 7 6 1 79 . 3 4 6 . 0 4 9 11 . 5 7 3 . 3 4 5 3. 1 6 0 . 7 5 0 96 5 . 3 6 26 , 2 9 9 . 8 0 1 45 . 6 3 6 . 7 9 7 51 , 7 8 3 . 6 3 4 13 9 . 4 1 9 , 6 8 7 37 . 2 2 . 5 6 6 5. 3 3 . 5 7 8 1. 6 9 3 . 9 6 7 48 . 2 6 3 . 5 9 7 73 , 2 9 . 1 8 5 81 . 6 1 7 . 6 5 24 7 . 4 9 8 . 5 4 9 LG S M a r g n a l S u b s t a t i o n C o Cl a s s Pe a k Mi d Of Ot h e r To t l LG S . 2 S 6. 5 9 2 , 4 8 0 77 2 . 2 8 8 22 9 67 . 3 5 5 7, 4 3 2 . 3 5 2 LG S . 2 P 17 7 . 3 3 2 21 . 2 7 2 7 1. 8 2 8 20 0 . 4 3 9 LG S o 2 T LG S . 3 S 4. 5 1 0 . 4 4 9 54 1 . 0 5 4 16 6 46 . 4 4 1 5. 0 9 . 1 1 0 LG S . 3 P 3. 3 3 5 . 6 7 5 39 9 . 0 3 1 12 2 33 , 2 5 2 3. 7 6 8 , O a o LG S - 3 T To t l 16 . 4 9 8 . 9 8 1 Cl a s s LG S . 2 S - W f ) LG S . 2 P . W P LG 8 - 2 T . W P LG S - 3 S . W P LG S - 3 P - W P LG 8 3 T . W P To t l WP M a r g i n a l S u b s t a t i n C o s t s U s i n g A n n u a l S c l i n g Pe a k M i d O f O t h e 12 1 . 2 9 9 1 4 . 2 1 0 4 1 . 2 9 15 . 7 5 9 1 . 8 9 0 1 1 6 2 o 0 0 0 14 2 . 1 5 2 1 7 . 0 5 2 5 1 , 4 6 4 20 3 . 8 8 2 4 . 3 9 0 7 2 . 0 3 2 o 0 0 0 To t a l 13 6 . 7 5 2 17 . 8 1 3 o 16 0 . 6 7 3 23 0 . 3 1 2 o 54 5 . 5 0 0 NP C Co t P e r i o R a t i o o f W P K w h t o L G S k w h A n n u a l Pe a k M i d O f f O t h e r A v e r a g e 1, 3 4 % 2 , 1 3 % 5 , 3 7 % 0 . 9 2 % 1 . 8 4 % 10 . 7 7 % 1 0 . 3 5 % 1 0 . 4 4 % 8 . 0 0 % 8 . 8 9 % 13 . 6 2 % 3 3 , 5 0 % 4 6 , 1 3 % 2 0 . 9 0 % 2 5 . 2 2 % 0, 3 5 % 2 . 8 4 % 6 . 3 9 % 2 . 7 4 % 3 . 1 5 % 0. 9 3 % 3 , 0 9 1 1 , 1 0 % 6 . 0 1 % 6 . 1 1 % 32 , 8 0 % 5 1 . 3 3 % 7 6 . 0 9 % 5 1 . 7 1 % 5 4 . 2 7 % 1. 4 % 3 . 9 0 % 9 . 3 3 % 4 . 4 7 % 4 . 9 8 % WP M a r g i n a l S u b s t a t i o n C o s t U s i n g T i m e o f U s e S e a l i n g Pe a k M i d O f O t h e r T o t a l 88 . 6 3 9 1 6 . 4 6 9 1 2 6 2 1 0 5 . 7 4 2 19 . 0 9 3 2 . 2 0 1 1 1 4 6 2 1 . 4 4 1 o 0 0 0 0 15 . 7 6 3 1 5 . 3 6 2 1 1 1 , 7 2 3 2 . 4 0 8 31 . 0 8 3 1 2 . 3 1 0 1 4 1 . 9 9 8 4 5 . 4 0 5 o 0 0 0 0 20 4 . 9 9 Pe r c n t Di f f e r e n c e 29 ,1 7 % 0% 39 6 % 40 7 % 0% 16 6 . 1 3 % ex h I b i t D E P . 1 Pa g e 2 o f 3 $ Di f r e n c e -3 1 . 0 1 0 3, 6 2 8 o -1 2 8 . 2 6 5 -1 8 4 . 9 0 7 o -3 4 0 , 5 5 3 "-e e Ne v a d a P o w e r C o p a n y Ma r g i n a l N o n R e n u e F e e e r C o s t s Co p a r i s o n o f A n n u a l S c l i n g o f M a r g i n a l C o t a n d T i m e o f U s e S c l i n g Kw h Us a g e Cl s s Pe a k Mi d Of Ot h e r To t a l LG S . 2 S 21 9 . 7 4 5 , 1 2 7 21 1 . 6 4 1 . 1 4 3 33 8 . 5 0 . 1 3 4 1 . 2 5 3 . 0 1 2 , 4 7 2 2 , 0 2 2 . 9 0 4 , 8 7 6 LG 5 - 2 P 5. 7 5 0 . 3 7 7 5, 7 6 8 , 7 6 5 10 . 1 2 1 . 9 1 5 39 , 5 0 1 , 3 0 3 61 , 1 4 2 . 3 6 0 lG 5 - 2 T 52 9 . 7 1 8 52 9 . 2 8 2 1. 0 3 8 . 5 4 8 4. 6 1 9 , 7 3 4 6, 7 1 7 , 2 8 2 LG S . 3 S 15 2 , 0 5 7 . 1 5 8 15 1 . 3 4 4 , 8 3 1 26 7 . 9 9 2 , 8 3 6 95 9 , 9 9 7 , 8 5 9 1 , 5 3 1 , 3 9 2 . 4 8 4 LG 5 - 3 P 11 5 , 7 4 9 . 9 3 9 11 6 . 3 6 , 2 2 20 6 . 9 1 5 , 8 0 2 75 9 , 7 0 4 , 8 1 3 1 . 1 9 8 , 7 3 8 . 8 1 6 LG 5 - 3 T 12 , 4 5 3 , 6 1 0 12 . 1 1 1 . 9 9 1 25 , 6 6 9 . 0 4 7 10 0 . 1 4 5 . 6 9 4 15 0 . 3 8 0 , 3 4 2 NP C To t a l L G S 50 . 2 8 5 . 9 2 9 49 7 , 7 6 4 , 0 7 4 85 0 , 2 4 4 . 2 8 2 3 . 1 1 6 , 9 8 1 . 8 7 5 4 , 9 7 1 . 2 7 6 . 1 6 0 Co t P e n o R a t i o o f W P K w h t o l G S k w An n u a l Pe a k Mi d Of f Ot h e r Av e r a g e LG S - 2 S - W P 2. 9 5 . 5 8 1 4. 5 1 3 . 2 1 4 18 . 1 7 9 . 4 2 6 11 , 5 7 3 . 3 4 5 37 , 2 2 0 . 5 6 6 1. 3 4 % 2. 1 3 % 5.3 7 % 0.9 2 % 1. 8 4 % LG S . 2 P . W P 61 9 , 1 2 7 59 6 . 9 3 2 1, 0 5 6 . 7 6 9 3, 1 6 0 , 7 5 0 5, 4 3 3 , 5 7 8 10 . 7 7 % 10 . 3 5 % 10 . 4 4 % 8. 0 % 8. 8 9 % LG S - 2 T - W P 72 , 1 7 2 17 7 , 3 2 7 47 9 . 1 0 8 96 5 , 3 6 0 1, 6 9 3 , 9 6 1 13 . 6 2 % 33 . 5 0 % 46 . 1 3 % 20 . 9 0 % 25 , 2 2 % LG 5 - 3 S - W P 53 1 . 4 0 6 4,2 9 7 . 1 2 2 17 , 1 3 5 , 2 6 8 26 . 2 9 9 , 8 0 1 48 . 2 , 5 9 7 0. 3 5 % 2. 8 4 % 6. 9 % 2. 7 4 % 3, 1 5 % LG 5 - S P - W P 1, 0 7 8 . 6 0 6 3. 5 9 0 , 0 6 5 22 . 9 6 , 7 1 7 45 , 6 3 6 , 7 9 7 73 , 2 9 , 1 8 5 0. 9 3 % 3. 9 % 11 . 1 0 % 6. 0 1 % 6. 1 1 % LG S - 3 T - W P 4, 0 8 4 , 7 7 1 6. 2 1 7 , 4 9 0 19 . 5 3 1 , 7 6 1 51 , 7 8 3 . 6 3 4 81 . 6 1 1 , 6 5 6 32 , 8 0 % 51 , 3 3 % 16 , 0 9 % 51 . 7 1 % 54 . 2 7 % To t l W P 9, 3 4 0 . 6 6 3 19 . 3 9 2 , 1 5 0 79 . 3 4 6 , 0 4 9 13 9 , 4 1 9 . 6 8 7 24 7 , 4 9 8 . 5 4 9 1. 8 4 % 3. 9 0 % 9.3 3 % 4. 4 1 % 4, 9 8 % Cl a s s i: 2 S LG S - 2 P LG S . 2 T LG 5 - S LG 5 - P LG S - 3 T To t a l LG S M a r g i n a l N o n R e v e n u e F e e e r C o s t s Mi d O f O t h e r 1. 1 6 9 , 9 2 2 3 4 7 1 0 2 . 0 3 4 32 , 2 2 4 1 0 2 . 7 6 9 To t a l 11 , 2 5 9 , 1 0 7 30 3 , 6 3 9 o 7,7 2 3 , 0 1 6 5, 1 0 8 , 1 8 2 ° 24 , 9 9 3 . 9 4 Pe a k 9. 9 8 . 8 0 26 8 , 6 3 6 6. 8 3 2 , 1 8 1 5, 0 5 3 , 1 4 1 81 9 . 6 3 0 60 , 4 8 25 2 18 5 70 . 3 5 3 50 . 3 7 3 Cl a s s i: 2 $ ~ W P LG S . 2 P . W P LG S . 2 T . W P LG S . 3 S - W P LG S - 3 p . W P LG 5 - 3 T . W P To t a l WP M a r g i n a l N o n R e v e n u e F è e d e r C o t s U s i n g A n n u a l S e a l i n g Pe a k M i d O f f O t h e r 18 3 , 7 5 3 2 1 . 5 2 6 6 1 , 7 7 23 , 8 7 3 2 . 8 6 4 1 2 4 6 o 0 0 0 21 5 . 3 4 3 2 5 . 8 3 2 8 2 , 2 1 7 30 8 . 8 5 8 3 6 , 9 4 7 1 1 3 . 0 7 9 o 0 0 0 To t l 20 7 . 1 6 3 26 , 9 8 4 o 24 3 , 4 0 0 34 8 , 8 9 5 o 82 6 . 4 4 1 WP M a r g i n a l N o n R e v e n u e F e e e r C o s t s U s i n g T i m e o f U s e S c a l i n g Pe a k M i d O f O t e r T o t a l 13 4 , 2 7 7 2 4 . 9 4 8 1 9 9 4 2 1 6 0 . 1 8 7 28 . 9 2 3 3 , 3 3 4 1 2 2 2 3 2 , 4 8 0 o 0 0 0 0 23 , 8 7 9 2 3 . 2 7 2 1 6 1 . 9 2 7 4 9 . 0 9 47 . 0 8 7 1 8 . 6 4 9 2 1 3 . 0 2 6 6 6 . 7 8 3 o 0 0 0 0 31 0 . 5 4 To t a M a r g i n a l C o s t . A n n u a l S e a l i n g 2. 1 7 0 , 9 0 2 T e t l M a r g i n a i C o t s . T i m e o f U s e S C a l i n g 87 5 . 7 1 3 1 4 7 . 9 0 % - 1 , 2 9 5 . 1 8 8 Pe r c e n t Di f f e r e n c e 29 . 3 3 % -1 6 . 9 2 % 0,0 0 % 39 5 . 7 8 % 40 7 . 2 4 % 0. 0 0 % 16 6 Ex b i t D E P - 1 Pa g e 3 o f 3 $ Di f f e r e n c e :: 6 5. 4 9 7 o -1 9 4 . 3 0 5 -2 8 0 , 1 1 2 o -5 1 '.e e ..e e Comparison of Annual Scaling of Marginal Cost and Cost Period Scaling Kwh UsageClassPeakMidOff Other Total PeakLGS-2S 219,745,127 211,641,143 338.506,134 1,253,012,472 2.022,904,876LGS.2P 5,750,377 5,768,765 10,121.915 39,501,303 61,142,360LGS.2T 529,718 529,282 1.038,548 4,619,734 6,717,282LGS-3S 152,057,158 151,344,631 267,992,836 959,997,859 1,531,392,484LGS-3P 115.749.939 116,368,262 206,915,802 759,704,813 1,198,738.816LGS-3T 12,453,610 12,111.991 25.669,047 100,145,694 150,380,342Total LGS 506.285,929 497,764,074 850,244.282 3.116,981,875 4,971,276,160 Cost lGS-2S-WP 2,954,581 4.513,214 18,179,426 11,573,345 37.220,566 1,34%LGS-2P-WP 619,127 596,932 1.056,769 3,160,750 5,433,578 10.77%LGS-2T-WP 72,172 177,327 479,108 965,360 1,693,967 13.62%LG8-3S-WP 531,406 4,297,122 17,135,268 26,299,801 48,263,597 0.35%LGS-3P-WP 1,078,606 3.590,065 22,963,717 45,636,797 73,269,185 0.93%LGS-3T-WP 4,084,771 6,217,490 19,531,761 51,783,634 81.617.656 32.80%TotalWP 9,340,663 19,392,150 79,346,049 139,419,687 247,498,549 1.84% lGS Marginal Transmission Costs Class Peak Mid Off Other TotalLGS.2S 6,939,330 812,920 241 70.899 7,823,390LGS-2P 186,662 22,391 7 1,924 210,984LGS-2T 15,271 1.820 1 173 17,265LGS-3S 4,747.758 569,520 175 48,885 5,366,338LGS-3P 3,511,175 420,025 128 35,002 3,966,330LGS-3T 360,005 42,161 16 3,729 405,911Total17,790,218 WP Marginal Transmission Cost Using Annual Kwh Scaling WPMargClassPeakMidOffOtherTotalPeakLGS-2S-WP 127,681 14,957 4 1,305 143,947 93,303LGS-2P-WP 16,588 1,990 1 171 18,750 20,097lGS-2T-WP 3,851 459 0 44 4,354 2.081LGS-3S-WP 149,631 17,949 6 1,541 169,126 16,592LGS-3P-WP 214,610 25,673 8 2.139 242,430 32.719LGS-3T-WP 195,390 22,883 9 2,024 220,305 118,081Total798.911 LGS Marginal Substation Costs Class Peak Mid Off Other TotalLGS-2S 6,592,480 772,288 229 67,355 7,432,352lGS-2P 177,332 21.272 7 1,828 200,439LGS-2T lGS-3S 4,510,449 541,054 166 46,441 5,098,110LGS-3P 3.335,675 399,031 122 33,252 3,768,080lG8-3T Total 16,498.981 . WP Marginal Substation Costs Using Annual Scaling WPM .e e Class Peak Mid Off Other Total PeakLGS-2S-WP 121,299 14,210 4 1,239 136,752 88,639LGS-2P-WP 15,759 1,890 1 162 17,813 19,093LG5-2T-WP 0 0 0 0 0LGS-3S-WP 142,152 17,052 5 1,464 160,673 15,763LGS-3P~WP 203,883 24,390 7 2,032 230,312 31,083LGS-3T-WP 0 0 0 0 0Total545,550 Class LGS-2S lGS-2P LGS-2T lGS-3S LGS-3P LGS-3T Total Class LGS-2S-WP LGS-2P-WP LGS-2T-WP LGS-3S-WP LGS-3P-WP LGS-3T-WP Total LGS Marginal NonRevenue Feeder CotsPeak Mid Off Other 9,986,80 1,169,922 347 268,636 32,224 10 Total 102,034 11,259,107 2,769 303,639 o 7,723.016 5,708,182 o 24,993,944 6,832.781 5,053.141 819,630 604,483 252 185 70,353 50,373 WP Mar9in~1 NonRevenue Feeder Costs Using Annual ScalingPeak Mid Off Other Total 183,753 21,526 6 1,87723,873 2,864 1 246o 0 0 0 215,343 25,832 8 2,217 308.858 36,947 11 3,079o 0 0 0 WP Margin Peak 207.163 26,984 o 243,400 348,895 o 826,441 134.277 28,923 o 23,879 47,087 o Total all Scaled Marginal cost 2,170,902 .'e Mid Off Other Period Ratio of WP Kwh to LGS kwh 2.13% 10.35% 33.50% 2.84% 3.09% 51.33% 3.90% 5.37% 10.44% 46.13% 6.39% 11.0% 76.09% 9.33% 0.92% 8.00% 20.90% 2.74% 6.01% 51.71% 4.47% Total Annual Ratio WP/LGS 1.84% 8.89% 25.22% 3.15% 6.11% 54.27% 4.98% inal Tranmsission Cost Using Time of Use Kwh ScalingMid Off Other Total17,335 13 6552.317 1 154610 0 3616.170 11 1,339 12.958 14 2,10321.643 12 1,928 arginal Substation Cost Using Time of Use Scaling 111,306 22,569 2.727 34,113 47,794 141.664 360.173 e Percent $ Difference Difference 29.33% -32.641 .16.92% 3.819 59.66% -1.627 395.78% -135.013 407.24% -194.636 55.51% -78.640 121.81% -438,738 Percent $ .e e," Mid Off Other Total Difference Difference16,469 12 622 105,742 29.33%-31,0102.201 1 146 21,441 -16.92%3,62800000.00%0'15,362 11 1,272 32,408 395.78%-128,26512,310 14 1.998 45,405 407.24%-184,90700000.00%0 204,996 166.13%-340,553 al NonRevenue Feeder Costs Using Time of Use ScalingMid Off Other Total24,948 19 9423,334 1 222o 0 023,272 16 1,92718,649 21 3,026o 0 0 Percent $ Difference Difference 29.33% -46,976-16.92% 5,4970.00% 0 395.78% -194,305 407.24% -280,1120.00% 0 166.13% -515,897 160,187 32.480 o 49,094 68,783 o 310.54 875,713 147.90%-1,295,188 -77,985 9,125 o -322,570 -465.020 o -856,450 ~ Ne P o r C o n y Sl a t e e n t 0 ; P a l l m p l e m e n l a t i o n Re c o " " i a l i o 0 1 M a r g i n C 0 5 t 1 0 t h e R e v e n u R e q u ~ e m n i Ei i b i O E P . Oi b u l i M a i o l C o T. . , . . a . . l C O I Ge & e n e i u M a l i n a l C O l i TO l Co Cu t o 0 l Tl l o s . En Ge E" " WA P A El l Y Dll Ad . F o r Ad f o Ba Sp e Co l Tr a Co s l Ge n r . . . ' 0 H o D & E W L O C o B a s e d H o o r Co t Cl s s So e . . Pe n e n l Re r u e t , O1 n , R e v , WI O C S F Fa c l l l e s B a s o c R R De m a n d Pe . . e n i e a s e R F De m a n d W A P A H o W P A P e l t l R R W L O a d i , A d , Ba s e R R RM 57 . 4 8 8 14 . 7 2 % (3 . 7 6 6 ) 37 . 9 4 4 37 , 9 4 4 P. 7 7 8 10 . 9 6 % 7,3 1 7 50 , 8 8 8 96 . 3 5 14 7 . 2 3 10 4 5 ' 4 11 2 . 8 9 (2 , 9 8 ) 10 9 , 9 1 0 RS 19 5 , 9 4 1 50 . 2 0 ' 4 (2 , 3 0 ) 13 9 , 9 0 8 13 9 . 9 0 39 , 7 8 3 44 . 6 0 ' 4 29 , 7 7 1 22 , 3 0 5 30 , 9 7 4 52 5 , 2 7 9 37 . 2 8 " 4 40 2 . 7 4 1 (9 . 0 5 5 ) 39 , 8 8 lR S 93 0, 2 4 % (1 6 ) e& 88 18 8 0.2 1 ' 4 14 1 1.0 6 1 1.9 8 3,0 4 6 0, 2 2 2,3 3 5 (8 3 1 2. 7 2 GS 20 , 6 0 2 5. 2 8 ' 4 (2 8 0 ) 14 , 8 7 3 14 , 6 7 3 2,5 7 8 2, 8 9 % 1, 9 2 9 15 . 4 8 29 . 2 4 7 44 , 7 3 8 31 7 % 34 . 3 0 ~, 3 O lG S I 54 , 6 6 14 0 0 % (7 0 ) 39 , 6 0 2 38 , 0 2 13 , 8 0 15 4 8 % 10 , 3 3 3 77 , 3 7 3 15 7 , 3 3 0 23 4 , 7 0 3 16 6 6 % 17 9 , 9 5 1 17 9 . 9 5 1 lG S 2 S 25 . 9 2 0 66 4 ' 4 (1 ) 18 . 8 1 2 18 , 8 1 2 7.8 2 3 67 7 % 5.8 5 4 42 . B 4 3 10 0 , 5 3 5 14 3 , 3 7 B 10 , 1 7 % 10 9 , 8 3 1 10 9 , 9 3 1 lG S 2 P 64 0 01 6 ' 4 48 5 46 5 21 1 02 4 % 15 B 1. 1 9 4 2,9 5 1 4. 1 4 5 02 9 % 3.1 7 8 3,1 7 8 lG S 2 T 30 8 00 8 % 22 4 22 4 17 00 2 % 13 89 30 7 39 6 00 3 ' 4 30 30 lG 5 - 15 , 8 7 5 40 1 ' 4 14 S 12 , 2 7 12 , 2 8 7 5. 3 8 6. 0 2 % 4. 0 1 6 28 . 8 8 1 74 , 9 9 10 3 , 8 8 3 1. 3 7 % 79 . _ 19 , _ LG S 10 . 8 6 2. 7 8 % 58 8, 4 8 8. 4 8 9 3. 9 8 4. 5 % 2, 9 l 21 . 8 8 57 , 8 7 8 79 , 3 8 5.8 3 % 60 . 8 ~ 60 . 8 5 1 LG S 3 T 1.3 0 1 0. 3 3 73 1. 1 7 1. 0 1 7 40 04 6 % 30 2, 2 9 8,8 9 1 9,1 8 8 06 5 % 7. 0 4 3 7, l U LG $ . X S 82 0.2 % 9 69 26 95 60 00 1 % 45 32 2 87 9 1,2 0 1 00 9 % 92 1 92 1 LG $ . X P 2, 7 9 5 0.7 2 % 29 8 2.3 2 7 2,2 9 1 4. 1 6 2.0 5 0 2.3 0 % 1,5 3 4 10 . 9 1 8 29 . 5 5 8 40 . 7 4 28 7 % 31 , 0 3 2 31 . 0 3 2 LG S X T 31 2 0.0 6 % 31 8 60 4 86 7 1.4 1 1 2,7 4 6 30 8 % 2.0 5 5 15 , 1 0 1 38 , 7 8 2 51 , 8 8 36 8 ' 4 39 . 7 6 4 (8 3 8 1 38 . l l LG $ ' 2 - W P S 55 01 4 % '1 8 42 3 42 3 11 1 0.1 2 % 83 83 2 1, 7 6 1 2.3 9 9 01 7 % 1.8 3 1, 8 lG $ ' 2 - W F 79 0, 0 2 % 3 80 60 23 00 3 % 17 13 2 26 7 39 00 3 % 30 30 lG S . W P 38 00 1 % 1 27 27 3 0. 0 0 % 2 8 77 85 00 1 % 85 85 lG S 3 - W P 24 8 0. 0 8 % 23 20 3 20 3 34 0.0 4 ' 1 25 99 2, 1 8 9 2,2 8 8 0.1 6 % 1. 7 5 4 1,7 5 4 lG S . J W P P 29 9 0, 0 8 % 38 25 3 25 3 47 0.0 5 % 35 20 1 3, 2 4 4 3,4 4 5 02 4 % 2,1 1 1 2.1 1 1 lG 5 . J W P 19 3 0.0 5 % 40 18 0 18 0 14 1 o 1 Er 10 8 79 7 3, 6 1 2 4, 4 0 03 1 . 4 3, 3 8 3, 3 8 SS T 0 0, 0 0 0 0 0 00 0 0 0 00 0 % 0 0 SL 71 8 0.1 8 % 76 (8 1 5D l 5G 1 82 00 7 % 48 29 1 6,6 7 5 6, _ 04 9 % 5. 3 4 1 5,3 4 1 RS , P A l 13 7 0. 4 % Il 99 0 0, 0 0 0 58 58 00 0 % 43 (2 ) 41 GS . P A l 34 9 0,0 9 % 25 3 25 3 0 0. 0 0 0 15 G 15 0 00 1 % 12 2 12 2 AI W P 0 0.0 0 % 0 0 0 0, 0 0 0 0 0,0 0 % 0 0 39 0 . 3 2 5 10 0 . 0 0 % 2, 2 8 3 8, 4 4 5 27 9 1 3 8 3,1 6 4 26 2 . 3 2 89 , 2 0 2 10 0 . 0 0 % es , 7 5 2 49 2 , 6 2 0 91 6 5 0 5 1 4 0 1 2 5 1 1 , 8 0 4 0 3 12 9 3 \ 1 0 6 7 . 4 6 Su o ! AØ I , Su m CO l B a i e d PF Fa a l t i Co B a s e C" " . RR w i o P F I1 r c e n l Ad ! . & Ma t n i RR RM 15 5 , 1 7 2 10 . 9 5 % 15 5 , 1 7 2 RS 58 , 3 6 5 aG . 7 7 % 56 3 , 3 8 LR S 3, 0 7 8 02 2 % 3.0 7 8 GS 5O , 1 l 2 35 1 1 5O , 1 l 2 lG S . i 22 , _ 16 2 3 % 14 1 22 , 9 0 1 LG S o 2 S 13 4 , 5 9 7 D5 0 % 44 13 4 , 1 1 1 LG S . 2 P 3. 8 0 0 0.2 7 % 1 6 3,8 0 7 LG S . 2 T 54 0 0,0 4 " , 0 54 LG S 3 S 95 , 9 3 6.7 7 % 34 95 , 9 6 6 LG S 3 P 72 , 2 6 7 5,1 0 % 26 36 72 , 3 4 9 LG S 3 T 8.3 6 0, 5 9 % 2 8, 3 8 LG S X S I, o e 0, 0 7 % 4 1,0 8 4 LG S - X P 37 , 1 1 1 2. 6 2 % 20 3 75 37 , 4 8 2 LG s X T 42 , 4 7 3 3, 0 0 % 21 75 42 , 5 6 9 LG S ' 2 . W P 2,3 4 8 0. 1 7 % 2 2. m LG S o 2 . W F 36 3 0, 0 3 % 1 38 LG S . 2 - W P 94 00 1 % 94 LG S . 3 - V I 1, 9 8 01 4 % 1 1. 9 B lG S . J W P P 2.9 3 0 0. 2 1 % 2. 9 3 lG S . 3 - W l T 3. 6 6 0.2 6 % 3, 6 6 SS T 0 00 0 % 12 0 SL 5,9 7 8 0.4 2 % 5,9 7 8 RS P A l 14 0 0,0 1 ' " 14 0 GS A l 37 6 0.0 3 ' " 37 5 A1 W P 0 0.0 0 % 0 14 1 8 . 5 3 7 1 36 5 19 3 1,4 1 7 0 8 3 e e ..e e NPC Distribution Marginal Costs . DistributionClass RM 57468 14,69%-3766 37,853 37,853RS19594150.09%-2306 139,597 139,597 " LRS 938 0.24%-16 663 663 ;;;~GS 20602 5.27%-280 14,640 14,640 ~"'.LGS-1 54660 13.97%-70 39.515 39 515 ~ , '-:"1LGS-2S 25920 6.63%-1 18.771 18,771 ïLG8-2P 640 0.16%463 463 ,LGS-2T 308 0.08%223 223 '~'l=-LGS-3S 15875 4.06%745 12,242 12.242 -',LGS-3P 10865 2.78%583 8,452 8,452LGS-3T 1301 0.33%73 1.015 1,015LGS-XS 82 0.02%9 68 26 94LGS-XP 2795 0.71%298 2,322 2291 4,613LGS-XT 312 0.08%378 60 867 1,471LGS-2-WPS 636 0.16%18 479 479 -77.98527LGS-2-WPP 70 0.02%3 54 54 9.125091LGS-2-WPT 36 0.01%1 27 27 0LGS-3-WPS 571 0.15%23 437 437 -322.5703LGS-3-WPP 764 0.20%36 589 589 465.0197LGS-3-WPT 193 0.05%40 180 180 0SST°0.00%0 0SL7180.18%76 -6 590 590RS-PAL 137 0.04%99 99 GS-PAL 349 0.09%253 253AIWP00.00%0 ° - 391181 2283 -6445 279136 3185 282321 . -856.4502 283298 282,320 Cost PwrFac Addl Fac Total - - Cost RRClassRRPercentAdjContractsCost RR Base RM 155,172 10.95%155,172 155.172RS563,365 39.77%563,365 563,365LRS3,078 0.22%3.078 3,078GS50,902 3.59%50,902 50,902LGS-1 229,886 16.23%14 1 229,901 229,901LGS-2S 134,597 9.50%44 134.641 134,641 LGS-2P 3.800 0.27%1 6 3.807 3,807LGS-2T 540 0.04%0 540 540LGS-3S 95,932 6.77%34 95,966 95,966lGS-3P 72,287 5.10%26 36 72,349 72,349lGS-3T 8,364 0.59%2 8,366 8,366LGS-XS 1,060 0.07%4 1,064 1,064LGS-XP 37,184 2.62%203 75 37,462 37,462LGS-XT 42,473 3.00%21 75 42,569 42.569LGS-2-WPS 2,346 0.17%2 2,348 2,348lGS-2-WPP 383 0.03%1 384 384 ..e e LGS-2-WPT 94 0.01%94 94LGS-3-WPS 1,983 0.14%1 1,984 1.984LGS-3-WPP 2,930 0.21%2.930 2.930LGS-3-WPT 3,666 0.26%3,666 3,666SST00.00%12 0 0SL5,978 0.42%5.978 5,978RS-PAL 140 0.01 %140 140GS-PAL 375 0.03%375 375AIWP00.00%0 01,416,537 365 193 1,417,083 1,419.524 1.417.081 2443 .'e e with Scling Adjustment , Transmission Costs Total Adjust5746814.72%37,944 37,944 .9778 10.91%728119594150.20%139,908 139,908 39783 44.38%296249380.24%665 665 188 0.21%140206025.28%14,673 14,673 2578 2.88%19205466014.00%39,602 39,602 13808 15.40%10282259206.64%18,812 18,812 7823 8.73%58256400.16%465 465 211 0.24%1573080.08%224 224 17 0.02%13158754.07%12,267 12,267 1:5366 5.99%3996108652.78%8,469 8,469 3966 4.42%295313010.33%1,017 1,017 406 0.45%302820.02%69 95 60 0.07%4527950.72%2,327 4,618 2050 2.29%15273120.08%604 1,471 2746 3.06%2045558.01473 0.14%423 -56 423 144 0.16%107 -32.6410879.125091 0.02%60 7 60 19 0.02%14 3.819349360.01%27 0 27..6 0.01%4 .3.117909248.42975 0.06%203 -233 203 169 0.19%126 -135.0132298.98028 0.08%253 -336 253 242 0.27%180 -194.6361930.05%180 0 180 -'220 0.25%164 -78.6404600.00%0 0 0 0.00%07180.18%591 591 62 0.07%461370.04%99 99 0 0.00%03490.09%253 253 0 0.00%000.00%0 0 0.00%0390324.55 279,136 -618 89642 100.00%66752 -40.2293 -1296.679 Present Percent First First First First First FirstPercentRevIncreaseCapReallocRemainPercentAllCap10.95%144051 7.72%o .155171.7 18.39%17643.4 172,81539.76%424559 32.69%464866 98499.27 0 0.00%0 464,8660.22%2803 9.81%3069 8.913007 .0 0.00%0 3,0693.59%46716 8.96%0 50902.08 6.03%5787.693 56,69016.22%238967 -3.79%0 229901.4 27.25%26140.36 256,0429.50%:u.. 15308.97 149.950144581-6.88%0 134640.6 15.96%0.27%3934 -3.22%0 3807.46 0.45%432.9176 4,2400.04%347 55.59%397 142.889 0 0.00%0 3976.77%104259 -7.95%0 95965.69 11.37%10911.54 106,8775.11%75826 -4.59%0 72349.35 8.57%8226.3 80.5760.59%8654 -3.33%0 8366.169 0.99%951,2541 9,3170.08%1188 .10.42%0 1064.245 0.13%121,0073 1,1852.64%36816 1.75%0 37461.87 4.44%4259.507 41,7213.00%40123 6.10%0'.42568.64 5.05%4840.16 47,4090.17%2145 9.45%0 2347.7 0.28%266.9393 2,6150.03%315 22.04%360 24.4263 .0 0.00%0 360 .e e 0.01%94 0.49%0 94.4567 0.01%10.73996 1050.14%2298 -13.66%0 1983.997 0.24%225.5854 2,2100.21%3317 -11.67%0 2929.791 0.35%333.1245 3,2630.26%3905 -6.11%0 3666_327 0.43%416.8705 4.0830.00%0 0.00%0 0 0.00%0 00.42%8719 -31.43%8719 -2740.514 0 0.00%0 8,7190.01%150 -6.42%0 140.371 0.02%15.96053 1560.03%410 -8.48%0 375.2129 0.04%42.66264 4180.00%0.00%0 0 0.00%0 012939999.49%95934.99 84737 e e Generation Energy wlo Total wlO Energy RR Savings Demand Hoover Hoovers Percent w/o Hoover97780.109617 7317.131 50888 96350 147238 10.45%112,800397830.445989 29770.65 222305 302974 525279 37.28%402,7411880.002108 140.6853 1061 1985 3046 0.22%2,33525780.028901 1929.184 15489 29247 44736 3.17%34,300138080.154795 10332.88 77373 157330 234703 16.66%179,95178230.0877 5854.154 42843 100535 143378 10.17%109,9312110.002365 157.896 1194 2951 4145 0.29%3,178170.000191 12.72154 89 307 396 0.03%30453660.060156 4015.517 28887 74996 103883 7.37%79,64939660.04461 2967.861 21689 57676 79365 5.63%60.8514060.004551 303.8203 2295 6891 9186 0.65%7,043600.000673 44.89956 322 879 1201 0.09%92120500.022982 1534.068 10918 29556 40474 2.87%31,03227460.030784 2054.903 15107 36782 51889 3.68%39,784111.3589 0.001248 83.33277 .24 632 1767 2399 0.17%1,83922.81935 0.000256 17.07631 3 132 267 399 0.03%3062.882091 3.23E-05 2.156744 .2 8 77 85 0.01%6533.98683 0.000381 25.43322 -100 99 2189 2288 0.16%1,75447.36398 0.000531 35.44369 -145 201 3244 3445 0.24%2,641141.3595 0.001585 105.783 -58 797 3612 4409 0.31%3,38000000.00%0620.000695 46.39621 291 6675 6966 0.49%5,34100056560.00%430001591590.0%12200000.00%089201.77 1 66752 .326 492620 916505 1409125 1 1080403 First Second Reveue Second Second Secnd Second Second Third % Change Cap For Reali Remain Percent All CapRR % Change Cap19.97%157721.4 15,094 0 0 0 157721.4 9.49%09.49%0 0 0 0.00%0 464866 9.49%09.49%0 0 0 0.00%0 3069 9.49%021.35%53485.15 3,205 0 0.00%0 53485.15 14.49%07.15%0 0 229901.4 38.79%7729.633 263771.4 10.38%03.71%0 0 134640.6 22.71%4526.819 154476.3 6.84%07.79%0 0 3807.46 0.64%128.0125 4368.39 11.04%014.41%0 0 0 0.00%0 397 14.41%02.51%0 0 95965.69 16.19%3226.511 110103.7 5.61%06.26%0 0 72349.35 12.21%2432.494 83008.14 9.47%07.67%0 0 8366.169 1.41%281.2832 9598.706 10.92%0-0.23%0 0 1064.245 0.18%35.78151 1221.034 2.78%013.32%0 0 37461.87 6.32%1259.524 42980.9 16.75%42150.6418.16%45936.82 1,472 0 0.00%0 45936.82 14.49%021.89%2455.811 159 0 0.00%0 2455.811 14.49%014.29%0 0 0 0.00%0 360 14.29%0 e e 11.91%0 0 94.4567 0.02%3.175777 108.3724 15.29%107.6206-3.85%0 0 1983.997 0.33%66.70497 2276.287 -0.94%0-1.63%0 0 2929.791 0.49%98.50399 3361.42 1.34%04.56%0 0 3666.327 0.62%123.2674 4206.465 7,72%00.00%0 0 0 0.00%0 0 0.00%00.00%0 0 0 0.00%0 8719 0.00%04.22%0 0 140.371 0.02%4.719485 161.051 7.37%01,92%0 0 375.2129 0.06%12.61522 430.4908 5.00%00.00%0 0 0 0.00%0 0 0.00%019,929 592746.9 e e i'.NPC Scaling Hoover Energy , Total Adjusted SNWa Adj Total . CostRR CostRR Difference dOnly,-2980 109,910 155,04 155,172 -127 -9055 393,686 562,908 563,365 -458 -63 2,272 ~3,076 3,078 .2 34,300 50,860 50,902 -42 179,951 '..229,749 229,886 .138 109,931 ;,134,527 134,597 -70 3,178 v 3,799 3,800 -2 304 539 540 .1 79,649 95,887 95,932 -45 60,851 ~.72,256 72,287 -32 7,043 8,361 8,364 -4 921 1,060 1,060 0 31,032 37,172 37,184 -12 -838 38,946 42,462 42,473 -11 1,839 2,425 2,346 79 79 306 374 383 -10 -10 65 97 94 2 2 1,754 2,317 1,983 334 334 2,641 3,411 2,930 481 481 3,380 :3,724 3,666 58 58 ° .,1 0 0 ° 5,341 .5,977 5,978 -1 -2 41 #.140 140 0.122 '375 375 -1 0 0 0 0 .12938 1067465 'I'1416537 1416537 -8.58E-12 944.5003t: Rev for Third .. Third Third Third Third Fourth Reali Remain ., Percent Alloc C8pRR % Change Cap 0 0 0 0 157721.4 9.49%0;. 464866 9.49%00o 1 0 0 0 0 0 0 3069 9.49%0 0 o ,r 0 0 53485.15 14.49%0 0 229901.4 .0.414095 344.1189 264115.6 10.52%0 0 134640.6 "0.242512 201.5314 154677.9 6.98%0 0 3807.46 .0.006858 5.699046 4374.089 11.19%0 0 0.'0 0 397 14.41%0 0 95965.69 ;:0.172852 143.6424 110247.4 5.74%0 0 72349.35 .0.130314 108.2933 83116.44 9.61%0 0 8366.169 -0.015069 12.52257 9611.229 11.06%0 0 1064.245 .0,001917 1.592973 1222.627 2.91%0 830.2632 0 0 0 42150.64 14.49%0 0 o 'u'0 0 45936.82 14.49%0 0 o .0 0 2455.811 14.49%0 0 0'0 0 360 14.29%0 e e 0.751843 0,.,0 0 107.6206 14.49%0 0 1983.997 ;0.003574 2.969667 2279.257 -0.82%0 0 2929.791 0.005277 4.385342 3365.805 1.47%0 0 3666.327 .~0.006604 5.487796 4211.953 7.86%0 0 0 0 0 0 0.00%0 0 0 0 0 8719 0.00%0 0 140.371 0.000253 0.210109 161.2611 7.51%0 0 375.2129 "-0.000676 0.561623 431.0524 5.13%aa00000.00%0831.0151 555190.6 4.61E+08 e e Certification Kwh LGS-2S-WP 2.954,581 4.513,214 18,179,426 11.573,345 37.220.566 LGS.2S 219,745,127LGS-2P-WP 619.127 596,932 1,056,769 3.160,750 5,433,578 LGS-2P 5,750,377LGS-2T-WP 72,172 177,327 479,108 965.360 1,693,967 LGS-2T 529,718LGS-3S-WP 531,406 4,297,122 17,135,268 26,299,801 48,263,597 LGS-3S 152,057,158LGS-3P-WP 1,078,606 3,590,065 22,963,717 45,636,797 73,269,185 LGS-3P 115,749,939LGS-3T-WP 4,084,771 6,217,490 19,531,761 51,783,634 81,617,656 LGS-3T 12,453,610 9,340.663 19,392,150 79,346,049 139,419,687 247,498,549 506,285,929 LGS-2S-WP 7.94%12.13%48.84%31.09%100.00%LGS-2S 10.86%LGS-2P-WP 11.39%10.99%19.45%58.17%100.00%LGS-2P 9.40%LGS-2T-WP 4.26%10.47%28.28%56.99%100.00%LGS-2T 7.89%LGS-3S-WP 1.10%8.90%35.50%54.49%100.00%LGS-3S 9.93%LGS-3P.WP 1.47%4.90%31.34%62.29%100.00%LGS-3P 9.66%LGS-3T-WP 5.00%7.62%23.93%63.45%100.00%LGS-3T 8.28%3.77%7.84%32.06%56.33%100.00%10.18% Peak Only Percent LGS-2S-WP 11.52%17.60%70.88%100.00%LGS-2S 28.54%LGS-2P-WP 27.24%26.26%46.50%100.00%LGS-2P 26.57%LGS-2T-WP 9.91%24.34%65.76%100.00%LGS-2T 25.25%LGS-3S-WP 2.42%19.56%78.02%100.00%LGS-3S 26.61%LGS.3p.WP 3.90%12.99%83.10%100.00%LGS-3P 26.36%LGS-3T-WP 13.69%20.84%65.47%100.00%LGS.3T 24.79%8.64%17.94%73.41%100.00%27.30% Last Case Certification Kwh LGS-2S-WP 2,594,784 3,456,756 16,088,819 7,654,423 29,794,782 LGS.2P-WP 110,542 131,481 306,113 790,036 1,338,172 lGS-2T-WP 89,968 188,171 448,921 927.859 1,654,919 LGS-3S-WP 1,135,933 2,668,807 15,162,796 33,722,011 52.689,54 7 LGS-3P-WP 1,966,055 3,910,641 17,589,600 39,665.609 63,131,905 LGS-3T-WP 2,332,478 5,762,965 23.918,299 72,296,858 104,310,600 8,229,760 16,118,821 73,514,548 155,056,796 252,919,925 LGS-2S-WP LGS-2P-WP LGS-2T-WP LGS-3S-WP 8.71% 8.26% 5.44% 2.16% 11.60% 9.83% 11.37% 5.07% 54.00% 22.88% 27.13% 28.78% 25.69% 59.04% 56.07% 64.00% 100.00% 100.00% 100.00% 100.00% ..e e lGS-3P-WP 3.11 %6.19%27.86%62.83%100.00%LGS-3T-WP 2.24%5.52%22.93%69.31 %100.00% 3.25%6.37%29.07%61.31%100.00% .-e e 211.641,143 338,506,134 1,253,012.472 2.022.904,876 5,768,765 10,121,915 39,501,303 61,142.360 529,282 1,038,548 4,619,734 6,717,282 151,34,631 267,992,836 959,997,859 1,531,392,484 116,368,262 206.915,802 759,704,813 1,198,738.816 12,111,991 25,669,047 100,145,694 150,380,342 497,764.074 850,244.282 3.116,981,875 4,971,276,160 10.46%16.73%61.94%100.00% 9.43%16.55%64.61%100.00% 7.88%15.46%68.77%100.00% 9.88%17.50%62.69%100.00% 9.71%17.26%63.38%100.00% 8.05%17.07%66.59%100.00% 10.01%17.10%62.70%100.00% 27.49%43.97%100.00% 26.66%46.77%100.00% 25,23%49.51%100.00% 26.49%46.90%100.00% 26.51%47.13%100.00% 24.11%51.10%100.00% 26.84%45.85%100.00% .."e e CERTIFICATE OF SERVICE J hereby certify that I have this day sered a copy of Southern Nevada Water Authority's Prefied Testimony of Denns Peaseau, Phase II - Rate Design upon each of the parties listed below by placing the same in the U.S. Mail postage prepaid, or electronically, to the following: Kathleen Draklich Sierr Pacific Power 6100 Neil Road Reno, Nevada 89520 kdrakliCh~ç.com smcdonald šPpc.com nellianotmevp.com csilviera(gppc.com Staff Counsel Public Utilities Commission of Nevada 1150 East Wiliam Street Carson City, NV 89701 troberts~puc.stte.nv .us Alaina Burtenshaw Public Utilties Commission 101 Convention Center Drive, Suite 250 La Vegas, NV 891109 aburtens(guc.state.nv.us Tim Hay Attorney General's Bureau of Consumer Protection 1000 East Wiliam, Suite 200 Carson City, NV 89701 tdhayt!ag.state.nv. us Eric Witkoski Attorney General's Bureau of Consumer Protection 555 E. Washington St., Suite 3900 Las Vegas, NV 89101 epwitkos(!ag.state.nv.us Robert Crowell Crowell, Susich, Owen & Tackes P.O. Box 1000 Carson City, NV 89702 rcrowelllfadvocacy.net ¡'e e Doris Knesek USAN P.O. Box 1823 Caron City, NV 89702 doris~usan.carn-city.nv .US Lawrence Gollomp USDE 1000 Independence Ave., SW Washington, D.C. 20585 Lawrnce.GaUomp(á.doe.gov Dale Swan Exeter Associates. Inc. 5565 Sterrett Place. Suite 310 Columbia, MD 21044 dswanMYexeterassociates.com Mark Russell Mirage Casino-Hotel 3400 Las Vegas Blvd. South Las Vegas. NY 89109 mrussell(iirge.com mashcraft(âlaw.com Richard Emmons Michael Kostrinsky Harrah's Operating Company, Inc. One Har's Court La Vegas, NV 89119-4132 mkostrinsàlharr.coin remmons(âarrs.com Dan Reaser Shawn Elicegui 50 West Libery Street. S1. 1100 Reno, NV 89501 drserMYlionelsawyer.com seliceguiMYlionelsawyer .com mbowant.lionelsawyer.com Marie Marin-Kerr and Phil Wiliamson Bureau of Consumer Protection 1000 E Wiliam St., Suite 200 Carson City. NV 89701-3 i 17 mmerrCfag.state.nv.us pwiliamsonØJag.state.nv.us \ ~'.e e Bil Kockenmeister 6005 Plumas St., Suite 301 Reno, NV 89509 bily§alns.com Martha Ashcraf 3993 Howard Hughes Parkway Suite 600 Las Vegas, NV891 09 mashcraft(Btrlaw.com Michael P. Alcantar Donald Brookhyser Alcanta & Kahl LLP 1300 SW Fifth, Suite i 750 Portland, OR 97201 deb§a-klaw_com mpaCfa-klaw.com James Ross RCS, Inc. 500 Chesterfeld Center, Suite 320 Chesterfield, MO 63017 jimross(f-e-s-inc.com Michael Kur Boehm, Kurt & Lowr 36 East Seventh Street, Suite 21 10 Cincinnati, OH 45202 mkurtlawtW..oL.com MikePinnau Chemical Lime Company 3700 Hulen Street Ft. Worth, TX 76107 mpinnau(Bchemjcallime.com -J.: ~.. .......e Scott Craigie Present, Alrus Consulting 6005 Plumas, Suite301 Reno, NV 89509 Dated this 27th day of Januar, 2004. e .e BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA - .. ' : : ! Docket No. 02-11021 Direct Testimony of Dennis E. Peseau on behalf of the Southern Nevada Water Authority Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. A. My name is Dennis E. Peseau. My business address is Suite 250, 1500 Libert Street, S.E., Salem, Oregon 97302. Q. BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED? A. I am President of Utilty Resources, Inc. My firm consults on a number of economic, financial and engineering matters for various private and public . entities. Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? A. I am testifying on behalf of the Southern Nevada Water Authority (SNWA). Q. DOES ATTACHMENT 1 ACCURATELY DESCRIBE YOUR BACKGROUND AND EXPERIENCE? A. Yes. -1- e e Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? A. In this Docket No. 02-11021, Nevada Power Company ("Nevada Power") seeks authority to adjust the current Deferred Energy Accounting Adjustment ("OEM") rate and Sase Tari Energy Rate ("STER") such that the proposed adjusted rates result in an overall rate reduction of 5.6% for residential customers and a rate reduction of 5.1 % for nonresidential customers. These percentage decreases are the result of Nevada Power proposing to amortize its additional accumulated OEM balances of $195 million over a three year period, but reduce its BTER in this case by almost 20% over the present level to net to the resultant proposed overall rate decreases. In its Application and filing, Nevada Power also requests two specific waivers from deferred energy accounting provisions. Nevada Power first requests a waiver to deviate from regulations to defer and carry forward to the next deferred energy period "the accrued but unpaid costs associated with the disputed (Enron, Cal Pine, Morgan Stanley, Reliant, Sempra, Trans-Canada) claims of terminating suppliers", which it claims total $229 millon. (Application, Page 15). Nevada Power makes a second request to deviate from the regulations and seeks Commission approval for a new methodology for setting the BTER in this proceeding. The purpose of my testimony is to propose certain adjustments to the DEA rate and BTER rate based upon my differing opinions as to the appropriate levels of prudent fuel costs incurred by Nevada Power in its test -2- e e year October 2001-September 2002.My testimony also makes recommendations on Nevada Power's requests to deviate from normal deferred energy accounting regulations. Q. WHAT CONCLUSIONS HAVE YOU REACHED REGARDING THE PRUDENCE OF THE $195.7 MILLION IN ADDITIONAL DEA RECOVERY SOUGHT BY NEVADA POWER IN THESE PROCEEDINGS? A. I conclude that in this case Nevada Power's request is overstated by at least $90.8 milion. This overstatement appears to be the result of imprudent and unauthorized purchases for fuel that, peculiarly, were made at the exact same time for this test period as transactions that were found to be imprudent during the previous test period in Docket No. 01-11029. In other words, in the very same period of time, February-April 2001, ¡nwhich Nevada Power was found in Docket No. 01-11029 to have made imprudent and excessive power pu rchases, I find in the present case that imprudent transactions made at that time also affect an amount of its test year October2001-September 2002 expenses. In particular, i conclude that: 1. Although Nevada Power indicates in its filing that it incurred $265.9 milion in net natural gas and transportation costs in the test year, the Company incurred only $140.8 milion of actual costs for delivered natural gas. Nevada Power lost the difference, a net of some $125 millon, by speculating in financial derivatives. .3- e e 2. The Company neglected in this filing to reduce test year purchased power costs to comply with the Commission order in Docket No. 01-11029 that found that Nevada Power had imprudently overbought power during early 2001and that Nevada Power was required to reduce the OEM for not acquiring 25% of its forward power requirements in late 1999 at a price based upon a "Merril Lynch" proxy for the price of forward power. I did not have access to necessary documentation to complete either the overbought or Merril Lynch adjustment as i explain below. Although appropriate for the Commission to continue its precedent in this case, i have not developed the related adjustments and have focused solely on the new issue of imprudence as a result of speculation in natural gas financial derivatives. 3. The BTER rate set in this case should be adjusted upward in a manner that approximately offsets the $90.8 milion disallowance to DEA balances i am proposing, plus any and all other adjustments the Commission finds appropriate in this case, including the Merril Lynch adjustment. so as to preserve the abilit of Nevada Power to reduce rates to residential and nonresidential customers by 5.6% and 5.1 % respectively but also maintain the cash flow level requested by Nevada Power in this case. NEVADA POWER'S GAS COSTS AND FINANCIAL DERIVATIVES Q. WHAT IS THE ISSUE WITH RESPECT TO THE TEST YEAR RECOVERY OF NATURAL GAS COSTS SOUGHT BY NEVADA POWER? A. In Nevada Power's Exhibits E-2, Line 21 and E-3, Page 2 of 2, Line 26, the Company claims that it incurred Test Period Natural Gas Costs of $250,256,132, net of inventory adjustment. This amount is carried forward -4- e e with other test year fuel and purchased power costs to form the basis for establishing and collecting test year costs through an adjusted OEA rate. The $250,256,132 of gas costs is derived from Nevada Power Exhibit E-11.6, Page 3 of 6, Lines 21-31, Column (aa) as the difference betwen column (a a) subtotal of $265,860,683 and an adjustment of $15,604,551. Line 21 indicates that Total (delivered) Gas and Transportation costs in the test year were only $140,830,145. Line 23 of this same exhibit shows a line labeled "Less:Sales," that is, the revenues derived by Nevada Power from the sellng off of any excess or unused natural gas. But the sales revenues on Line 23 are added to, rather than subtracted from, the Line 21 total gas costs. In other words, by adding the sales revenue figure of Line 23 to Line 21, Nevada Power is in effect indicating that it paid parties in the test year $125,030,538 to take its excess gas. i initially assumed that the accounting here was simply in error, with an inadvertent error in sign, from negative to positive. The issue here is just what this "Less:Sales" figure of $125,030,538 represents, and why is the figure being added to test year costs and proposed to be charged to ratepayers? -5- e e Q. HAVE YOU DETERMINED THE SOURCE OF THE $125,030,538 THAT NEVADA POWER INCLUDES AS A NATURAL GAS COST? A. Yes. In a partial response to Data Request SNWA 17, a copy of which is shown in my Exhibit _ (DEP.,1), Nevada Power explains that the $125,030,538 is the sum of actual sales revenues for its excess gas, and losses it incurred in the use of financial derivatives, or financial trades during the test year. The figure of $125,030,538 is the sum of the sales revenues from resellng excess natural gas (and therefore a negative entry) and the actual losses of $133,184,681 the Company incurred by making "financial trades." This is why I qualified in my conclusions above that Nevada Power lost a "net" of $125 millon. It actually lost the $133.2 million. Q. WERE ANY ACTUAL OR PHYSICAL QUANTITIES OF NATURAL GAS PURCHASED OR RECEIVED IN THIS FINANCIAL TRADING? A. No, the $133,184,681 that Nevada Power is attempting to recover did not purchase a single molecule of gas. Nevada Power paid an additional sum of $140,830,145 for the actual gas that it burned in the test year. Q. WHERE IN NEVADA POWERlS FILING IS THE TOPIC OF THE LOSSES FROM FINANCIAL DERIVATIVES OF $133.2 MILLION ADDRESSED? A. This topic is neither addressed nor explained in the Company's filing, except for a one page vague reference to hedging strategy in the testimony of witness -6- e e Lorelei Reid, Direct, Page 4, Line 12, to Page 5, Line 15. This general discussion never references any of the financial consequences or circumstances under which these financial derivatives were entered or even that Nevada Power incurred such losses. Q. WHICH OF THE NEVADA POWER WITNESSES ARE RESPONSIBLE FOR ADDRESSING THE PRUDENCE OF TEST YEAR NATURAL GAS EXPENSES? A. The testimony of Mr. Coyle and the deposition of Mr. Branch both identify Ms. LoreLei Reid as the only witness addressing the issue of the prudence of test year natural gas expenses. Q. WHAT DOES MS. REID TESTIFY TO REGARDING THE COMPANY'S FINANCIAL OR IIHEDGING" STRATEGY FOR NATURAL GAS? A. From a literal reading of her testimony, Page 4, Line 12 to Page 5, Line 15, i inferred that at the September 5, 2001 Risk Management Committee ("RMC") meeting, which was just prior to the October 2001 start to the test year in this case, the RMC approved some form of hedging strategy for test period supplies of natural gas. Had this happened, the timing would have been almost perfectly consistent with the hedging strategies that Nevada Power and the RMC followed in the year prior. That is, on or about September 20, 2000 Nevada Power began engaging in hedging strategies (basis swaps and fixed -7- e e for floating swaps) gradually over a course of six or seven months for the Docket No. 01-11029 test year, which began October 2000. But, when I reviewed the September 5, 2001 RMC minutes referenced by Ms. Reid in the present case, I noted that the minutes reflected a request by her and subsequent approval by the RMC to hedge only 10.000 Dthlday for Nevada Power. Her testimony, Page 5, Line 5, indicates that the Company's needs were approximately 150,000 Dth/day. No RMC minutes subsequent to September 5, 2001, nor did the confidential gas purchase transaction sheets, indicate any later hedging activities. Q. WHAT DID YOU CONCLUDE FROM THESE MINUTES, AND MS. REID'S TESTIMONY? A. I concluded that Nevada Power either took a gas purchase position that was indexed to actual market prices for its remaining gas needs of approximately 140,000 Dthlday, or had conducted hedging activities prior to the September 5, 2001 time frame but was without a reference by or any discussion of in Ms. Reid's testimony. The latter conclusion seemed most plausible, as i could not understand. how the hedging position of the relatively modest quantity of1 0,000 Dth/day could have led to the huge test year losses of $133.2 milion. A gas purchase position that would have been indexed to the market pnce could not have produced any financial losses. -8- It e Q. HAVE YOU BEEN ABLE TO DETERMINE THE SOURCES AND CAUSES OF THE $133.2 MILLION LOSSES FROM HEDGING? A. Yes. Several months prior to September 5, 2001, over a period of just four specific days, February 22, and April 11, 12 and 27, Nevada Power entered into a limited number of very high priced basis hedges that produced the overwhelming percentage of its test year financial losses. The taking of these huge positions was inconsistent with an appropriate buy over time hedging strategy that was in place, as well as inconsistent with the gas hedging strategy that Nevada Power had implemented in the purchase of its Docket No. 01-11029 test year natural gas supplies. As I show below, had Nevada Power remained with its buy-over-time strategy, it could have reduced its test year natural gas costs that it attributes to financial derivatives in the present case test year by at least $91 millon. Q. WHAT NATURAL GAS PROCUREMENT POLICY WAS IN EFFECT AT NEVADA POWER DURING THE PERIOD IN WHICH THE TEST YEAR GAS HEDGES WERE MADE? A. There was no written natural gas procurement strategy in effect during the time frame that the hedging that took place on February 22, April 11,12 and 27,2001 (Reid dep., page 104, lines 12-24 and page 162, Lines 9-15). In addition, there were no discussions that could be recalled by Ms. Reid concerning these hedges prior to the February 22 or April 11 , 12 and 27, 2001 -9- e e purchases despite statements by Nevada Power that such discussions and pre-approvals are usual practice. Although Company protocol required signatures on trades by superiors, the approvals for the trades in question here were not obtained until after the trades had been executed (Reid dep., Page 55, Line 1 to Page 56, Line 24, and Page 143, Lines 3-16). Q. ARE THERE DOLLAR VALUE LIMITS ON THE RISK ASSOCIATED WITH THE FINANCIAL TRANSACTIONS THAT NEVADA POWER PERSONNEL CAN ENTER INTO? A. Yes. During the period in question, the dollar value limit for Ms. Reid to enter into natural gas transactions was $2 milion per trade. I am unable to explain how the February 22 and April 11 , 12 and 27 trades could have been entered into consistent with this restriction, given the eventual $133.2 milion losses associated with them.1 Ms. Reid's total of only six individual transactions on February 22 and April 11,12 and 27 for basis swaps alone totaled loss positions of over $90 millon. One trade was conducted on February 22, two trades conducted on April1, one trade on April 12 and two trades conducted on April 27. The losses associated with each trade ranged from over $5 millon individually for one trade, to over $30 milion. 1The dollar value limits of $2 milion were increased to $5 milion subject to Board approval, later at the May 23, 2001 RMC meeting. -10- e - Q. CAN YOU DETERMINE WHETHER THE RISK MANAGEMENT COMMITIE WAS OPERATING UNDER ANY DEFINED GAS PROCUREMENT DISCIPLINE? A. Minutes of an RMC meeting date February 29, 2001, Page 2, attached as my Exhibit _ (DEP-2) indicate that all members approved a motion to II ... continue the current buy over time strategy with respect to Nov.-Mar. 2002 ..." with respect to natural gas purchases. This same motion, however, required that"... by next meeting an outline of a fuel procurement strategy with respect to coal/gas be prepared assuming no divestiture of generation "... No such outline was prepared for the next RMC meeting of March 14, 2001, nor was any discussion or outline prepared prior to any of the February 22 and April 11, 12 and 27 trades made by Ms. Reid. I wish to make clear here that these February-April financial trades at that point in time were not for the coming summer months, but for the following 2002 winter and summer months. QUANTIFYING THE LOSSES OF THE GAS FINANCIAL DERIVATIVES Q. JUST WHAT DID NEVADA POWER DO IN TERMS OF TRANSACTIONS WITH FINANCIAL DERIVATIVES TO INCUR $133.2 MILLION IN LOSSES? A. There are two fundamental components to delivered gas costs: the actual or physical gas ("commodity") cost, and the transportation cost to the point of receipt ("pipeline" or "basis"). Unless Nevada Power holds contract capacity .11- e e on the pipelines serving Southern Nevada subject to FERC cost of service rates, the cost of each ofthese two components varies in today's gas markets under natural gas deregulation by the FERC. Therefore, in order for Nevada Power to completely fix a test year price of gas delivered to its system, which it apparently wished to do, the Company hedged both commodity prices ("fxed for floating or FFSWAP") and transportation delivery prices ("basis swap"). The $133.2 millon in financial hedging losses were the result of the market prices of both commodit and basis fallng dramatically after the hedges were put in place. From Exhibit 1 attched to the deposition of Lorelei Reid, the test year losses for each hedge can be seen as:2 Commodit: $36.8 milion loss Basis: $99.7 milion loss Q. SHOULD NEVADA POWER HAVE HEDGED GAS COMMODITY AND/OR BASIS IN THE MANNER IN WHICH IT DID? A. Absolutely not. At least three issues need to be addressed prior to entering such hedges: 1. Should hedges or fixed-price financial derivatives be used at all, or should the gas have been bought at indexed prices with no possible financial impact on the Company or its customers? 2. Did Nevada Power possess or feel that it possessed superior trading prowess or knowledge to "beat the market, II which in this instance meant that it knew that both commodity and basis prices would be higher over the October 2001-September 2002 2 Reid Deposition Exhibit 1, page 18 Grand Total for mark to market losses for FFSWAP (commodity) and page 32 Grand Total for mark to market losses for BASISSWAP. -12- e e test year, than the hedges it conducted in the February and April 2001 time period? 3. If Nevada Power did not possess superior market knowledge or abilities, then a hedge should always be done in increments, over time, to avoid taking a "price view" that is, making a bet that prices would continue upward. Q. PLEASE ADDRESS THE ISSUE OF WHETHER FIXED PRICE HEDGES SHOULD HAVE BEEN ENTERED. A. In retrospect the answer is easy. No. Gas costs would have been $133.2 milion lower absent the hedges. But the issue here regarding hedges is whether or not Nevada Power should be taking on such financial risk when it was anticipating to be or actually was under a deferred energy mechanism. The corollary issue is whether this risk should be borne by shareholders or ratepayers. Q. WHY DO YOU STATE THAT NEVADA POWER COULD HAVE AVOIDED THE USE OF FINANCIAL DERIVATIVES AND ASSOCIATED FINANCIAL RISK BY SIMPLY ENTERING INTO GAS CONTRACTS WITH PRICES INDEXED TO MARKET PRICES AT THE TIME OF GAS DELIVERY? A. Financial hedges are nothing more than bets between a part and counterpart. One part bets that prices are going to rise and the counterpart bets that prices wil decrease. In each financial hedge that was undertaken by Nevada Power, the Company was betting that gas prices would continue -13- e e upward. That is all that a financial hedge is: a contractual commitment to make a financial (only) settlement that is based upon the relationship between the hedged contract price, and the actual market price at the time of gas delivery. With gas that is purchased with prices that are indexed to market prices, no bet has been made, and no financial gains or losses are incurred.3 In such cases, Nevada Power simply receives and pays for natural gas at the prevailng market price and has no additional financial responsibility. Q. DID NEVADA POWER POSSESS SUPERIOR TRADING ABILITIES OR INFORMATION WHEN EXERCISING THE TEST YEAR HEDGES? A. No. As I explained above, there is no evidence of anything other than a buy over time gas purchase strategy in place at the Company prior to the February-April financial hedges and there were not even any discussions of pending expected commodity or basis price increases at the time in February and April 2002 when the hedges were made. Again, unless Nevada Power held strong, informed convictions that commodity and basis prices were going to rise above the then record level, then the financial hedges it entered could only have resulted in monetary losses. 3 Ms. Reid acknowledges this in regard to indexed prices "...Since the terminated supply contract were priced at index, the terminations had no financial impact on the Company or its customers,.. ..Direct, page 4, I 2-5). -14- e e Q. WERE THERE IN FACT DISCUSSIONS OR FORECASTS PRESENTED TO NEVADA POWER THAT COMMODITY AND BASIS PRICES WERE GOING TO DECREASE, NOT INCREASE AS IT BET? A. Yes, and subsequent price decreases that actually did ensue are what eventually led to the large financial losses. In March 2001 the investment banking firm of Goldman, Sachs & Co. made a presentation to Sierra Pacific Resources. A copy ofthe Goldman, Sachs & Co. presentation accompanies the minutes ofthe RMC meeting of March14, 2001. This presentation shows commodity and basis prices well below those that Nevada Power entered into on April 11, 12 and 27, 2001. Knowledge of these forecasts, but exercising the hedges anyway, greatly increased the financial risk ofthe Company's April 2001 hedges for the test year in this proceeding. Q. WHY DO YOU MAINTAIN THAT IN THE ABSENCE OF SUPERIOR MARKET KNOWLEDGE, HEDGES SHOULD ONLY BE IMPLEMENTED IN INCREMENTS, OVER TIME? A. If Nevada Power did not have a "price view," that is, a strong analysis or view that prices were going to rise, but stil wanted to fix its test year gas prices, the best procedure is to buy over time. This is sometimes referred to as price averaging. Buying over time is an acknowledgment that one does not expect to, at any point in time, beat the market. As commodities such as natural gas have price patterns that are cyclical, buying overtime moderates or eliminates -15- e e price risk. Some supplies are purchased at points on the price cycle below average prices; some supplies are purchased at points on the price cycle above average prices. Many studies indicate that commodity price movements are somewhat random and unpredictable and, in order to remove timing risk, should be bought overtime, thereby maximizing the probabilties of buying at averages over time. My Exhibit _(DEP-3) is an excerpt from the Company response to an oral request made at the deposition of Lorelei Reid and contains a WEFA consulting report made to Nevada Power that underscores the point that commodit prices and unpredictable. Q. DID, IN FACT, NEVADA POWER ENTER THESE COMMODITY AND TRANSPORTATION HEDGES AT THE "WRONG" TIME? A. Yes, Neva~a Power clearly entered these transactions at the top or high side of the price cycle. During the February-April 2001 time frame, both gas commodity and market basis prices were at all time record levels. Locking into hedges at this time is imprudent unless Nevada Power had strong information and advice that prices were to continue setting new record levels. As one might expect with commodity prices that are cyclical, actual gas commodity and basis prices plummeted two months after the execution ofthe hedges and huge financial losses ensued. My Exhibit_(DEP-4) shows the historical behavior of gas commodity and basis prices before, during and after the -16- e e February- April hedging. Nevada Power's timing could not have been worse, as both ofthese prices plummeted in the following two months. Q. DID NEVADA POWER USE A BUY OVER TIME HEDGING STRATEGY FOR ITS DOCKET NO. 01-11029 TEST YEAR NATURAL GAS PURCHASES? A. Yes. The test year for Docket No. 01-11029 was October 2000-September 2001. From a review of files of transactions sheets for gas hedging provided by Nevada Power, I was able to determine that the Company's hedging positions in this prior deferred energy test year occurred over an approximate six month period beginning in September 2000. Over this period, Nevada Power purchased approximately equal quantities of gas in a disciplined manner over time. If the Commission rules that it was prudent for Nevada Power to use financial derivatives at all in acquiring natural gas supplies, then i recommend that the Commission impose a buy over time hedging strategy that re-prices Nevada Power's present test year hedges according to a six month gradual purchase period. Q. WHY DO YOU MAKE THIS RECOMMENDATION? A. I realize that dealing in financial hedges is risky business. Financial derivatives do not reduce gas costs over time, they only introduce price certinty. But there is no means to know ahead whether these certain prices -17- -e are above or below market. In order to benefit at all from these financial hedges, the hedging must be done gradually over time. BENEFICIARIES OF GAINS FROM NEVADA POWER SPECULATION IN FINANCIAL DERIVATIVES Q. DID THE COUNTERPARTIES TO THE FEBRUARY-APRIL FINANCIAL HEDGES WITH NEVADA POWER MAKE SUBSTANTIAL MONETARY GAINS? A. Yes. In these few hedging transactions, Nevada Power's losses were the counterparties' gains. Counterpartes gained over $133 milion on these few financial hedges, in a penod of a few days. Q. WHO BENEFITTED FROM NEVADA POWER'S HEDGED TRANSACTIONS? A. Interestingly, only three counterparties were involved in all of the commodity and basis transactions with Nevada Power. GAS COST ADJUSTMENTS TO REFLECT PRUDENT HEDGING Q. HOW DO YOU PROPOSE TO ADJUST THE FINANCIAL LOSSES FROM NEVADA POWER'S HEDGING TO REFLECT A GRADUAL, BUY OVER TIME PROCUREMENT STRTEGY? -18- e e A. I propose to re-price the actual hedging transactions made by Nevada Power by using the actual market prices for these hedging instruments that existed at mid-month in each of the six months prior to the period of gas delivery. In other words, rather than use the commodity and basis prices that Nevada Power locked into because of its concentrated purchases, I use the actual market prices of such financial derivatives that Nevada Power would have experienced had it followed its buy over time strategy. Q. PLEASE EXPLAIN. A. My Exhibit _ (DEP-5) reflects two hedging strategies. The left-most box of this exhibit, "NPC Acquisitions," shows the actual commodity (NYMEX Fixed for Floating Swaps) and basis (SoCal Basis Swaps) trnsactions that Nevada Power entered into. The purchases are broken into the typical gas contract winter and summer periods, November 2001-March 2002 and April 2002- October 2002, respectively. For example, the commodity hedges entered by Nevada Power for the gas in winter of the test year were for 70,000 MMBTUlday at an average winter price (for the commodity only) of $4.91. For the summer, the position was for 55,000 MMBTU/day at an average price of $3.10. Similarly, the winter basis or transportation component of gas also had a position of 70,000 MMBTU/day. but was entered at an average price of -19- e e $4.14. The summer position of 50,000 MMBTUlday had an average price of $4.94. Q. WHAT DOES THE BUY OVER TIME STRATEGY IN YOUR EXHIBIT _(DEP-5) SHOW? A. The right-most box of Exhibit _(DEP-5) shows the differences in the financial commodit and basis prices that would have occurred had Nevada Power more closely adhered to its buy over time strategy, and had it not attempted to time the market in the February and April time frame. The Buy Over Time Strategy re-pnces Nevada Powets trades according to mid-month commodit and basis trades in each of the six months prior to seasonal requirements. The re-pnced positions result in commodity prices of $3.95 and $2.78 for winter and summer periods, respectively. The re-pnced positions result in basis prices of $1.04 and $.04 for winter and summer periods, respectively. Q. WHAT DOES YOUR EXHIBIT _ (DEP-6) SHOW? A. Exhibit _ (DEP-6) computes the adjustment to test year natural gas costs that is necessary to reflect the reduced commodity and basis pnces that should have been experienced under Nevada Power's stated purchasing policy. -20- e e The total financial derivatives cost is computed for Nevada Powets financial derivatives cost as well as the financial derivatives cost of the buy overtime strategy. Had Nevada Power followed its buy overtime strategy, its test year natural gas costs would have been $90,763,715 lower. This amount of unnecessary additional cost was incurred imprudently and should be removed from the OEM balances in this case. Q. EXHIBIT _ (DEP-6) REFLECTS NATURAL GAS COST DIFFERENTIALS FOR ONLY THE ELEVEN MONTH PERIOD NOVEMBER 2001- SEPTEMBER 2002. WHY? A. Although October 2001 is in the current test year, the gas supplies for this month were obtained as part of the summer acquisitions made for the previous test year. As i find no fault with the procurement policies from the last test year, I make no adjustment for October 2001. SOUTHWEST GAS COMPANY COSTS OVER SAME PERIOD Q. DID YOU COMPARE THE PURCHASE STRATEGIES AND RESULTING GAS COSTS WITH OTHER NATURAL GAS PURCHASERS IN THE REGION? A. Yes. My Exhibit_(DEP-7) compares the unit gas costs experienced by Nevada Power and Southwest Gas Company over the course of the test year. While Nevada Power paid an average price of $6.39/0th in this test year, -21- e e Southwest Gas paid an average of only $3.88/Dth. The Commission has determined that the average cost paid by Southwest Gas was prudent for this period in the most recent PGA case. Had Nevada Power an average price of $3.88/Dth, its test year gas costs would have been $98.4 millon lower. OVERBOUGHT AND MERRILL LYNCH ADJUSTMENTS Q. WHAT ARE THE ISSUES WITH RESPECT TO YOUR REFERENCES TO THE OVERBOUGHT AND MERRILL LYNCH ADJUSTMENTS? A. In Docket No. 01-11029 the Commission found that Nevada Power had continued to purchase power even after it had reached its stated objective of107% of average peak loads. The Commission quantified the amount of imprudent costs associated with the excess purchases and denied the recovery of such costs. In the present case, Nevada Power's load and resource balances appear to indicate a lesser, although significant amount of excess purchases in certain months of the test year. Nevada Power has proposed no adjustment in this case for excess purchases. I have not been able to estimate the amount of any imprudent expenses for an overbought position in this case; due in part to lack offull access to necessary documents data. I did not participate in the FERC proceedings for the terminated purchased power contracts, nor did I have access to the terms and conditions for the Duke Energy contract renegotiations. I have not reviewed the Duke contracts as they are confidential and have not been given to me. -22- e e With respect to the Merril Lynch adjustment, I did not consider this issue in Docket No 01-11029, although I understand that the Commission ordered that this adjustment be made. Nevada Power has apparently not followed through in this case with the Commission ordered Merrill Lynch adjustment. Although I have not been able to follow through with an independent Merrill Lynch calculation of my own in the present case, I do not disagree wih the Commission order on this issue. I have also seen the Nevada Power response to MGM 6-01 in this case that contains additional details of the terms and conditions of the Merril Lynch transaction. I understand that certain other parties are addressing this issue in the present case. SUMMARY AND CONCLUSIONS Q. PLEASE SUMMARIZE YOUR RECOMMENDATIONS AND CONCLUSIONS. A. My review and recommended adjustments in this case have been limited to the test year natural gas costs incurred by Nevada Power. My review indicates that Nevada Power lost $ 133.2 milion through financial derivatives intended to speculate that gas commodit and basis prices were going to rise, despite a lack of analysis to support this speculation. i have re-priced these hedging losses to reflect the level of losses that would have been incurred by Nevada Power if it had followed its stated strategy of purchasing on a "buy over time" basis. My analysis indicates that an amount of $90.8 milion of losses were the result of imprudent decisions -23- e e resulting from the Company deviating from its own strategy. i re1h the Commission order Nevada Power to remove $90.8 millon from its proposed OEM balances. The BTER issue has been a moving target throughout discovery and depositions in that Nevada Power has requested approval of the new purchased power contracts, but has not responded to requests to demonstrate the effect of these contract prices and provisions on the BTER. Thus the rationale and justification given in the direct testimony is not applicable. The costs developed. in his testimony are no longer a reliable basis upon which to estimate fuel and purchased power costs for the BTER. Natural gas price have also increased somewhat since the filing of Mr. Branch's testimony. Without information on the degree of hedging undertaken by the Company and the terms of the proposed contracts, i cannot reliably quantify a BTER. i propose that the Commission order Nevada Power to exactly offset the DEA adjustments that i, and others propose, and which the Commission accepts, with an upward adjustment to the BTER proposed by Nevada Power in this case. Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? A. Yes. -24- ~.e ~ Exhi~it (DEP 1) Page 1 or2, NEVADA POWER COMPANY RESPONSE TO INFORMATION REQUEST DOCKET NO.: REQUEST NO.: REQUESTR: 02-11021 REQUEST DATE: Jan 29, 2003 WITNESS:SNWA17 Dennis Peseau RESPONDER:Rice, Bruce REQUEST: Regarding Exibit E 11.6, pages 2 and 3 of 6= Lines 23 of pages 2 and 3 of 6 show posive entris for "Sales". Sales revenues shold be used to reduce total gas costs, yet line 23 is added to line 21. increasing total gas cots: a. Should line 23 actually show negatie dollar values to reflec offsets to gas cots? Pleae explain. b. Why were th fine 23 Sales revenues reflected as negative values in the corresponding schedules in Docket No. 01-11 029? c. If NPC intends for line 23 reerenced above to actlly be poitve in this fifing. is NPC paying partes to take its gas supplies? Please explain. d. Please provide all workpapers. supporting docmentation and invoice pertining to all Exibit E- 11.6. RESPONSE: The "sales" shown on fine 23 represent net activity of sales (gas sold to c~stomers) and financial trades (hedges). Generally, NPC ' subtracts the sales of gas from total gas and transportation costs, thereby reducing total gas costs. The expenses of the financial trades (hedges) were greater than the sales for the test period ending September 2002. This resulted in a positive amount that is added to total gas and transportation costs. Please see the attached spreadsheet that details by month the amounts for sales and financial trades for both the current filing as well as Docket 01-11029. Oc I . ( 1 N o v - o i D e c - o i J a n . ( 2 F e b . o 2 M a r - 0 A p r . ( 2 M a t o 2 J u n . ( 2 J u l . ( 2 A u g . ( 2 S e p 2 Sa l e s ( 4 , 4 0 5 . 9 5 J . 5 8 ) ( 6 6 8 . 0 7 . 7 9 ) ( 1 . 2 3 8 . 7 2 0 . 8 0 ) Fi n T r a e s 2 2 . 1 0 8 . 9 3 . 0 0 I J , 7 0 . 2 7 0 . O O 1 4 . 9 4 6 . 1 3 8 . 0 0 17 . 7 0 2 , 7 3 9 . 4 2 1 2 , 4 0 1 , 4 6 2 . 1 1 3 . 7 0 7 . 4 1 7 . 2 0 (4 3 2 . 1 6 0 . 5 4 ) 14 . 2 0 4 . 5 2 5 . 0 0 i J . 7 7 2 . 3 6 4 . 4 6 (J 1 5 . 2 5 6 . 1 8 ) 13 . 9 7 5 . 4 6 6 . 0 0 13 . 6 6 0 . 2 0 9 . 8 2 (4 S 6 . 6 9 8 . 7 8 ) 14 , 7 3 J . 7 9 \ . 0 0 14 , 2 7 7 . 0 9 2 . 2 2 (1 5 . 8 0 0 . 0 0 ) 7.2 0 7 . 7 4 0 . 0 0 7. \ 9 1 . 9 4 0 . 0 0 (3 9 . 1 4 1 . 4 0 ) 7, 2 6 1 . 1 9 2 . 0 7. 2 2 2 . 0 5 0 . 6 0 (6 6 . 9 7 S . O O ) 7. 3 8 9 . 1 3 4 . S 6 7.3 2 2 . 1 S 9 . 5 6 (2 8 4 . 7 0 0 . 0 0 ) 6. S 4 . 3 2 3 . 8 3 6. 5 6 9 . 6 2 3 . 8 3 (6 4 . 0 5 0 . 0 0 ) 6. 2 S 8 . 6 9 . 3 3 6. 1 9 4 . 8 1 9 , 3 3 ( 1 6 5 . 8 7 8 . 4 0 ) S. I 7 . S 3 8 . 3 3 5. 0 0 8 . 6 5 9 . 9 3 TO ' l A I . (8 . 1 S 4 . 1 4 2 , 4 7 ) 13 3 . 1 8 4 , 6 8 1 . 0 5 12 5 . 0 3 0 . 5 3 8 . e "' t r ii ~ 0C : : CD 1 - . " C" NI - . rT o Hi l N""~'"t-.. .1 '$. :j~l::~ £~.~ ~1i:.~..~;' .' \,: ::.~: .~')~;'¡'4J 1 . ,e e Exhibit (DEP 2) Page i orZ , 'Mizmes fo th PL En Ri MaeiEi M. Comm~ Feb 29, 2001, 1:30PM - 3:30Pli heen ii.)) :R Holb Jef ~ Bül Bim Dae Bå, aD:M Smart(rc a qu). . "\ . .Guea: Ioii"Par. C:g Be Bar Al Cbc Bun, Mi Wei, Ga Cmyf ~ Joy Ái Au an Lo Rcd. '. . Absen MaRu an Bil Pe in cour in Ca Ci iedi th moon to st~ r: ra iic:f by th ea. . Mi Sm oped th me at i:30 PM .. ... . . .Cmg Be pn the: EMC wi an avew orth NP CE RF wh -w scou oIll~ 3d, 201 an Btnnir th pr wh we re 01. . Fcb 23 . 20 1. Th RF wa se ou to" 36 cn 8 ic wee ie Ct is a sica cODC be ra by tb re~. JdT -M corI fomc hi im pt=t noton mJ du to th 201 icac ai_,acn er te (~ m: in âb tlod pIcÇ iDte '. ~)' ar ,an.by ap ofth Jd re craupP.t: .Cr bidic th RF. . .ictc is in lbpr Dfcopict m inca '~ofpdcc an ~ , . '.': tc~ vd ca of1b ie I1 EMC ak th th ac .. . ;:bo~cf~~at.~~~~weO!Mait;200i.. 1h . " me ~ thmo otfb bi Il iiJl êh to 1b ui drstar th aiiD in th we tb coi fi"!sJ sion a: ui icgu is an ëo st M a ie a cm' copa a: wi bo,. diff. Som o!ib reìi a pi.to ad NPs 201 se buÌJ~ w) õtb did no. Th mite is al séc ~c. bids th ci.lb 2001 se.bu re~em an in on NPC-s plicare fopo du 2t..2010. 'I alve bid st wi8l NP to ~y dd 1b cost of th 2001 Je st fr th co oftbNPC"s phys powmre . .. . .. . .' I.ei ltd cU ~li 'ga ti åD suly üs A confider1Ù eg 'W sigo with Kc Ri Pi to al fo tb reea of th :m . re to tb oxn prec Qu is st yr ii in pacc wi1h NP in rq to a sc spli of th Ker pipeli exn. WPS ba st DOt si in rcpr 10 1h Tus exoo SPPCO b lm to si bc th bc if. we do not dive th copay re an ad lev of opoii 1hgb mullo pl ownp, SPPC i: in th, fi st of ncgoai for 24.s of . PG17ANGlOV À to co th ca~ iimi at Kiga . 1 ïil .' . ' :~.i?:1 , ".. :..:. -. ,.. . .' .. ~::i)..:.,~... ." . . ...:;..:"t~. .. ,..~.J ..' e e. .Exhibit __ (DEP ,2) Page 2 of 2 ' i Loreei an An Au t)'prec tw baut (oi for NPC th. oth fo SPPCo) shog 2001 sa poSIom pe th buge phys te and :6cialy hedged as of 2101. Mi ma a. motiODcons oftb pa (1) bf nc mcc an otd of .a. fu pren st wi n: to coga be pre as no dive .'.. of genoD, (2) fi th reeidcr of th Ap.( op po at (3) cont tlc cu bu oyer ti ~ with ieto Nov-Ma 200 .A mebe iivc the moon in atance " Mi Sma sinnBTze ef to ie th copay'i prcu st; wbchis ba on i 07 of avenge $h pe 1h rets oftb amys wi bembm ai th ne EMC me .. . Tmi Joyc snmønze ches th ar ie to th Ri Ma Pa1 in re~ to FAS 133 en bowc 1r ii~. ~vc an~1roi ~ wi . e~ma a dm of th prpo lae wj th DCwe wi a. vot to ippov th .dr lae at th ~ meetDB . Mie Sm an Dae Baby ~se th issu of oi bu at th pbm anjoi a¡ for anc to pos to finaize ib ceomics an ma a. deon whto pio'or not. A st ii wi be prdc at tJ ne EMe mcg.. . . Th ~mctü~ bc~fbtbweofW 12l1,201.. . . 'I mcgWl idou~at3~ ~ :..." '... . . \, 2 ." . . .' ., M. ~.. .' . . ". '" . .., .. . ': ~ ,.('¡:~..~., . ,.~~ e PR I C E F O R E C A S T I N G :. - , : . ~ : ~ ' . . ' \ 1 T . - , ' " , ' . ' . . . . . . ' V E f · ! \ '~ : ~ . : : . . . i . L O N G - T E R M IS EA S Y · E M F 6 , L Y N C H ( 1 9 8 9 ) , L Y N C H ( 2 0 0 0 ) . S H O R T - T E R M IS HA E R · I N H E R E N T L Y . P R I C E S A R E : '. · R A D O M e . S T O C H A S T I C · C H A O T I C · M E A N - R E V E R T I N G · U N P R E D I C T A B L E WE F A I n c . A P R ~ R K C o r n p a n y -e Exhibit _ (DEP 4) Price ($/mmbtu) Iz""3 CDx ~~~~..-I..-lo~~w~~æ~~~o~~w~~æ~000000000000000000000000000000000000 Jan-97 Apr-97 I i I I I i ;, i IJul-97, II '1111 Oc-9 . I i ,I IIII ~:: : ¡ , I,ll i 1IIIII I I Jul-9a I : I I i I i ! I ! I r I i L oc.g ii I I · i i i I !' . ¡. ai :: i 1111:11 iiilg:! Ju~ illllllllllllll'IIII~~."' C Oct-99 ¡ I I I i I I I i I I i I Pr ~~ ~J"-.. I "1 iiI '1=.1;' ~ CD Apr-QO I I . I I i I . i i I ~. ~- Jul-oO. I I. i I i I · i I 3l ~ cl Oct-OO I, I 'i I. ic.-, IJan-Q1 : CD..Apr-01 i II i I~::: . i I ' I i I ! IJa i I I I I i I~ ~I i Apr-Q2 i I I i . I i . 1 I Ii 'i I i I~ IIJul-02 I I I ¡ ~ I i i i 'i. i i ! Oct-02 I I i I I Jan-03 i I i I i I I , i I I i e '"IIp.~'- Do c k e t N o . 0 2 - 1 1 0 2 1 So u t h e r n N e v a d a W a t e r A u t h o r i Tr a n s a c t o n T i m i n g f o r N P C H e d g e s a n d B u y O v r T i m e S t r t e y ,¡.~.0.~~ NP C A c q u i s i t i o n s NY M E X F i x e d f o r F l o a t i n g S w a p s De l i v e r y P e r i o d : No v , 0 1 - M a r , 0 2 Ap r , 0 2 - 5 e p t , 0 2 Am o u n t Pr i c e Am o u n t Pr i c e Da t e o f A c , Mm b t u l a y $ / M m b t u Da t e o f A c a . M m b t u / D a y $ / M m b t u 22 - F e b - 0 1 20 , 0 0 0 5. 2 9 11 - A p r - 0 1 10 , 0 0 0 5. 1 0 22 - M a r - 0 1 10 , 0 0 0 5. 3 9 3- D e e - 1 10 , 0 0 0 2. 8 5 22 - M a r - 0 1 10 , 0 0 0 5. 3 5 17 - D e 1 5, 0 0 0 2. 9 0 3Q - M a r - 0 1 10 , 0 0 0 5. 3 0 24 - D e c 1 5, 0 0 0 2. 9 7 11 - A p r - 0 1 10 , 0 0 0 5. 1 0 25 - a o - o 2 10 , 0 0 0 2. 3 7 27 - 5 e p - 0 1 10 , 0 0 0 2. 6 7 8- F e b - 2 5, 0 0 0 2. 4 3 8- F e b - 0 2 10 , 0 0 0 2. 4 5 To t a l 70 , 0 0 0 4. 9 1 55 , 0 0 0 3, 1 0 So c a l B a s i s S w a p s De l i v e r y P e r i o d : No v , 0 1 - M a r , 0 2 Ap r . 0 2 - S e p t , 0 2 Am o u n t Pr i c e Am o u n t Pr i c e Da t e at A a i . Mm b t u D a v $ I M m b t u Da t e o f A c a . M m b t u / D a v $ / M m b t u 22 - F e b - 0 1 20 , 0 0 0 2, 1 5 11 - A p r - 0 1 20 , 0 0 0 5. 2 5 11 - A p r - 0 1 20 , 0 0 0 5. 2 5 11 - A p r - Q 1 10 , 0 0 0 5. 3 0 11 - A p r - 0 1 10 , 0 0 0 5. 3 12 - A p r - Q 1 10 , 0 0 0 5. 1 5 12 - A p r - 0 1 10 , 0 0 0 5. 1 5 27 - A p r - 0 1 5, 0 0 0 3. 8 0 27 - A p r - 0 1 5, 0 0 0 3. 8 27 - A p r - 0 1 5, 0 0 0 3. 6 5 27 - A p r - 0 1 5, 0 0 0 3. 6 5 To t a l 70 , 0 0 0 4 . 1 3 9 2 8 6 50 , 0 0 0 4. 9 4 e Bu y O v e r T i m e S t r a t e g y NY M E X F i x e d f o r F l o a t i n g S w a p s De l i v e r y P e r i o d : No v , 0 1 - M a r , 0 2 Ap r , 0 2 - S e p t , 0 2 Am o u n t Pr i c e Am o u n t Pr i c e Da t e o f A c a . Mm b t u a ' r $ I M m b t u Da t e o f A c . M m b t u l D a y $ / M m b t u 16 - M a y - Q 1 10 , 0 0 0 5. 0 5 16 - 0 c t - 0 1 5, 0 0 0 2, 8 3 15 - J u i r 1 15 , 0 0 0 4. 5 2 16 - N o v - 0 1 10 , 0 0 0 2, 9 4 16 - u l - 0 1 10 , 0 0 0 3, 8 5 17 - D e e 0 1 10 , 0 0 2. 8 5 16 - A u g - 0 1 15 , 0 0 0 3, 9 6 16 - J a n - 2 10 , 0 0 2, 5 3 17 - S e p - 1 10 , 0 0 0 3. 3 3 15 - F e b - 0 2 10 , 0 0 0 2, 4 5 16 - 0 c t - 0 1 10 , 0 0 0 2, 7 1 15 - M a r - 0 2 10 , 0 0 0 3, 1 6 To t a l 70 , 0 0 0 3. 9 5 55 , 0 0 0 2. 8 So c s l B a s i s S w p s De l i v e r y P e r i o d : No v , 0 1 - M a r , 0 2 Ap r , 0 2 - S e p t , 0 2 Am o u n t Pr i c e Am o u n t Pr i c e Oa t e o f A c q . Mm b t u / O a . . $ / m b t u Da t e o f A c . M m b t u D a y $ / M m b t u 16 - M a y - 0 1 10 , 0 0 0 3. 9 4 5 10 / 1 6 1 0 1 5, 0 0 0 0. 1 2 6 15 - J u n - 0 1 15 . 0 0 0 1. 2 6 5 11 / 1 6 1 1 10 , 0 0 0 0. 0 5 2 16 - u l - Q 1 10 , 0 0 0 0. 9 5 4 12 1 1 7 1 0 1 5, 0 0 0 0. 0 2 5 16 - A u g - 0 1 15 , 0 0 0 0. 2 6 0 1/ 1 6 1 2 10 . 0 0 0 -0 . 0 1 0 17 - S e p - 0 1 10 , 0 0 0 0, 0 5 2 21 1 5 / 0 2 10 , 0 0 0 0. 0 6 5 16 - o c t . 0 1 10 , 0 0 0 0. 0 3 9 3/ 1 5 / 0 2 10 , 0 0 0 0. 0 3 0 To t a l 70 , 0 0 0 1. 0 4 0 50 . 0 0 0 0. 0 4 3 e e Exhibit (DEP 6) Docket No. 02-11021 Southern Nevada Water Authont Adjustment for Over Time Buying NPC Financial Trades Nymex FFSwaps Nov,01-Mar,02 Apr,02-5ept,02 Total MMBtu/Day 70,000 55,000 Volume (MMBtu)10,570,000 9,615,000 20,185,000 Total Cost 51,928,900 29,778,525 81,707,425 $/MMBtu 4.91 3.10 4.05 SoCal Basis Swaps Nov,01-Mar,02 Apr,02-Sept,02 Total MMBtulDay 70,000 50,000 Volume (MMBtu)10,570,000 9,150,000 19,720,000 Total Cost 43,752,250 45,155,250 88,907,500 $/MMBtu 4.14 4.94 4.51 NPC Hedging Cost 95,681,150 74,933,775 170,614,925 Over Time Hedging Cost 52,745,055 27,106,155 79,851,210 Adjustment (42,936,095)(47,827,620.0)(90,763,715) ,.r-i;~ Do c k e t N o . 0 2 ~ 1 1 0 2 1 0" , Ne v a d a P o w e r C o m p a n y . S o u t h w e s t G a s ~.~ Co s t o f G a s C o m p a r i s o n .c.~ Co s t at .. So u t h w e s t Co s t a t N P C So u t h w e s t ~Pt Mo n t h NP C V o l u m e NP C $ l D t h $/ D t h $/ o t h $/ D t h Di f f e r e n c e e Oc t , 01 2, 7 1 6 , 9 3 1 10 , 1 5 4 2 2. 8 8 3 2 27 , 5 8 8 , 2 6 1 7, 8 3 3 , 4 5 5 19 , 7 5 4 , 8 0 5 No v , 01 2, 1 4 6 , 0 6 5 9. 5 0 5 1 4. 5 9 5 1 20 , 3 9 8 . 5 6 2 9, 8 6 1 , 3 8 3 10 , 5 3 7 , 1 7 9 De c , 01 3, 2 0 2 , 1 3 1 7. 5 9 4 0 3. 9 7 6 7 24 , 3 1 6 , 9 8 3 12 , 7 3 3 , 9 1 4 11 , 5 8 3 , 0 6 8 Ja n , 02 2, 9 4 1 , 2 8 4 7. 4 9 6 7 3. 8 2 2 0 22 , 0 4 9 , 9 2 4 11 , 2 4 1 , 5 8 7 10 , 8 0 8 , 3 3 6 Fe b , 0 2 2, 5 0 9 . 0 2 4 8. 0 6 3 8 3. 9 4 0 1 20 , 2 3 2 , 2 6 8 9, 8 8 5 , 8 0 5 10 , 3 4 6 , 4 6 2 Ma r , 02 2, 2 8 1 , 9 3 0 9, 2 7 1 2 4. 2 8 9 9 21 , 1 5 6 . 2 2 9 9. 7 8 9 , 2 5 2 11 , 3 6 6 , 9 7 8 Ap r , 02 2, 1 6 0 , 0 5 3 6. 5 5 6 9 3. 7 2 1 0 14 , 1 6 3 , 2 5 2 8, 0 3 7 , 5 5 7 6, 1 2 5 , 6 9 4 Ma y , 02 3, 3 2 4 , 6 8 1 5. 4 2 1 1 3. 7 5 6 0 18 , 0 2 3 , 4 2 8 12 , 4 8 7 , 5 0 2 5. 5 3 5 , 9 2 6 Ju n e , 02 4, 2 6 9 , 7 5 2 4. 8 0 8 8 3. 7 1 3 6 20 , 5 3 2 , 3 8 3 15 , 8 5 6 , 1 5 1 4, 6 7 6 , 2 3 2 Ju l y , 02 4, 7 3 1 . 0 5 9 4. 7 1 4 4 3. 9 7 0 8 22 , 3 0 4 , 1 0 5 18 , 7 8 6 , 0 8 9 3, 5 1 8 , 0 1 5 Au g , 02 4, 6 6 2 , 6 3 4 4. 3 9 8 4 4. 0 0 4 0 20 , 5 0 8 , 1 2 9 18 , 6 6 9 , 1 8 7 1, 8 3 8 , 9 4 3 Se p t , 02 4, 2 3 4 . 1 0 3 4. 4 8 3 2 3. 9 4 1 3 18 , 9 8 2 . 3 3 1 16 , 6 8 7 , 8 7 0 2, 2 9 4 , 4 6 0 To t a l 39 , 1 7 9 , 6 4 7 6. 3 8 7 4 3. 8 7 6 2 25 0 . 2 5 5 , 8 5 5 15 1 , 8 6 9 , 7 5 3 98 , 3 8 6 , 1 0 1 No t e : S o u t h w e s t G a s $ f D t h f o r A p r , 0 2 - S e p t , 0 2 a r e f o r e c a s t s . e So u r c s : S o u t h w e s t G a s 2 0 0 2 P G A F i l n g Ne v a d a P o w e r 2 0 0 2 O E M F i l n g e _achment1 Page 1 of 3 . ' STATEMENT OF OCCUPATIONAL AND EDUCATIONAL HISTORY AND QUALIFICATIONS DENNIS E. PESEAU Dr. Peseau has conducted economic and financial studies for regulated industries for the past twenty-eight years. In 1972, he was employed by Southern California Edison Company as Associate Economic Analyst, and later as Economic Analyst. His responsibilties included review of financial testimony, incremental cost studies, rate design, econometric estimation of demand elasticities and various areas in the field of energy and economic growth. Also, he was asked by Edison Electrical Institute to study and evaluate several prominent energy models as part of the Ad Hoc Commitee on Economic Growth and Energy Pricing. From 1974 to 1978, Dr. Peseau was employed by the Public Utilty Commissioner of Oregon as Senior Economist. There he conducted a number of economic and financial studies and prepared testimony 'pertaining to public utilties. In 1978 Dr. Peseau established the Northwest offce of Zinder Companies, Inc. He has since submitted testimony on economic and financial matters before state regulatory commissions in Alaska, California, Idaho, Maryland, Minnesota. Montana, Nevada, Washington, Wyoming, the District of Columbia, the Bonnevile Power Administration and the Public Utilties Board of Alberta on over one hundred occasions. He has conducted marginal cost and rate design studies and e .achment 1 Page 2 of3 prepared testimony on these matters in Alaska, California, Idaho, Maryland, Minnesota, Nevada, Oregon, Washington and in the District of Columbia. He has also conducted cost and rate studies regarding PURPA issues in the states of Alaska, California, Idaho, Montana, Nevada, New York, Washington. and Washington, D.C. Dr. Peseau holds the B.A., M.A. and Ph.D. degrees in economics. He has co-authored a book in the field of industrial organization entitled, Size. Profits and Executive Compensation in the Large Corporation. which devotes a chapter to regulated industries. Dr. Peseau has published articles in the following professional journals: Review Qf Economics and Statistics, Atlantic Economic Journal. Journal of Financial Management, and Journal of Regional Science. His articles have been read before the Econometric Society, the Western Economic Association, the Financial Management Association, the Regional Science Association and universities in the United Kingdom as well as in the United States. He has guest lectured on marginal costing methods in seminars in New Jersey and California for the Center of Professional Advancement. He has also guest lectured on cost of capital for the public utility industry before the Pacific Coast Gas and Electric Association, and for the Executive Seminar at the Colgate Darden Graduate School of Business, University of Virginia. e 4ttachment 1 Page 3 of 3 I . Dr. Peseau and his firm have participated with and been members ofthe American Economic Association, the American Financial Association, the Western Economic Association, the Atlantic Economic Association and the Financial Management Association. He was formerly a member of the Staff Subcommitee on Economics of the National Association of Regulatory Utilty Commissioners. Dr. Peseau has been President of Utility Resources, Inc. since 1985. . ' , ..e . AFFIRMATION I, Dennis E. Peseau, pursuant to NAC 703.710 hereby affirm that the foregoing prepared testimony was prepared by me or under my direction and is correct to the best of my knowledge. Signed ¡L fAuc~ Dated "'/Í~1- Z /idOi; . .. 2 3 4 5 6 7 8 9 ~o 10 ~ooN",11~Bo ¡'S ~12i: 00di~13o ø. .1 b ~ i:Z 14 Q.m~ 15ol _... GJ :; ()II ~ d Ø4 .. 0 16 i = ~iJ~U 17 II l" ãi t"18~ 19 20 21 22 23 24 25 26 27 28 . PROOF OF SERVICE . I hereby ceify that I mailed the foregoing Prepared Testimony of Dennis Peseau in Docket 02-11021 by delivering to the U.S. Post Offce copies thereof, properly addressed for mailing to the following persons: Beth Ellot Nevada Power Company MS 3A 6226 W. Sah Avenue Las Vegas, NV 89151 Timothy Hay Consumer Advocate Bureau of Consumer Protection i 000 E. Wiliam Street, Suite 200 Carson City, Nevada 89701 Lawrence Gollomp U.S. Deparent of Energy 1000 Independence Avenue SW Washington, DC 20585 Staf Counel Public Utilities Commission 1150 East Wiliam Street Carson City, NV 89701 Jon Wellnghoff Beckley Singleton Chtd. 530 Las Vegas Blvd. South Las Vegas, NV 89101 Mark Rusell Mirage Hotel & Casino 3400 La Vegas Blvd. South Las Vegas, NV 89109 Eric Witkoski, Nevada Attorney General's Offce 555 E. Washington St., Suite 3900 Las Vegas, NV 89101 ::ODMA\PDOS\HLRNOOOS\3234 73\ 1 Page 10f2 ~ .' . 1 2 3 4 5 6 7 8 9 ~o 10 ~ooM..11:iSo l'SS;12CI 00 cJ~13o l m '9 ~CI Ž 14 Q.~~ 15.l .. .pf i:; U. ~ èII .. 0 164) gi ~ ~~U 17 4) t" 'i t"18:i 19 20 21 22 23 24 25 26 27 28 e Jim Polito Bureau of Consumer Protection 1000 E. Wiliam Street, Suite 200 Carson City, NV 89701 Robert Crowell Crowell, Susich, Owen & Tackes, Ltd. P.O. Box 1000 Carson City, NV 89702 Joyce Newman Utility Shareholders Association P.O. Box 1823 Carson City, NV 89702 Gerald Lopez Colorado River Commission of Nevad 555 East Washington Avenue, Suite 3100 La Vegas, NV 89101 David J. Gildersleeve Nevada Energy Buyers Network 8685 W. Sahar Avenue, S1. 200 Las Vegas. NY 89117 Dale Swan Exeter Associates, Inc, 12510 Prosperity Drive, S1. 350 Silver Spring, MD 20904 James D. Salo Colorado River Commission of Nevada 555 East Washington Avenue, St. 3100 Las Vegas, NY 89101 Dated: March 7, 2003 . lsi An em DISON AND HOWARD 777 E. Wiliam Stree Suite 200 Carson City, Nevada 89701 ::ODMA\PCDOCS\HLRNODOS\23473\1 Page 2 of2