before the public matter of the - wyoming public...

BEFORE THE PUBLIC SERVICE COMMISSION OF WYOMINGIN THE MATTER OF THE APPLICATION OF )ROCKY MOUNTAIN POWER FOR APPROVAL )OF A GENERAL RATE INCREASE IN ITS )RETAIL ELECTRIC UTILITY SERVICE RATES ) Docket No. 20000-384-ER-bIN WYOMING, OF $97.9 MILLION PER ANNUM ) (Record No. 12702)OR AN AVERAGE OVERALL INCREASE OF )17.3 PERCENT

)APPEARANCES

For the Applicant PacifiCorp, d/b/a Rocky Mountain Power (Rocky Mountain Power or theCompany): PAUL J. HICKEY and O’KELLEY H. PEARSON of Hickey & Evans,Cheyenne, Wyoming; and DANIEL E. SOLANDER of Rocky Mountain Power, SaltLake City, Utah.

For the Intervenor Office of the Consumer Advocate (OCA): iVAN WILLIAMS andSTEFANIE BOSTER, Cheyenne, Wyoming.

For the Intervenor Wyoming Industrial Energy Consumers (WIEC): ROBERT M. POMEROY,JR., THORVALD A. NELSON, and ROBYN A. KASHIWA of Holland & Hart, LLP,Greenwood Village, Colorado.

For the Jntervenors, QEP Field Services Company (QEP) and Granite Peak Development, LLC(Granite Peak): DALE W. COTTAM and JEFFREY M. BOLDT, of Hirst Applegate,LLP, Cheyenne, Wyoming.

For the Intervenor Interwest Energy Alliance (Jnterwest): LISA TORMOEN HICKEY, ofAlpern, Myers, Stuart, LLC, Colorado Springs, Colorado.

For the Intervenor Cimarex Energy Co. (Cimarex): JULIA A. JONES, of Beatty & WozniakP.C., Denver, Colorado.

For the Intervenor Kinder Morgan Interstate Gas Transmission LLC (KMIGT): T. J. CARROLL,ifi, Vice President and Deputy General Counsel, Lakewood, Colorado.For the Intervenor AARP: KATE M. FOX, of Davis & Cannon, LLP, Cheyenne, Wyoming.For the Intervenor City of Casper, Wyoming (Casper): WILLIAM C. LUBEN, City Attorney,

and WALLACE E. TREMBATH, ifi, Assistant City Attorney, Casper, Wyoming.For the Intervenor Town of Bar Nunn, Wyoming (Bar Nunn): CHARLES S. CHAPIN, ofChapin & Dixon, LLP, Casper, Wyoming.

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For the Intervenor Natrona County, Wyoming (Natrona County): WILLIAM C. LUBEN,WALLACE B. TREMBATH, ifi and WILLIAM P. KNIGHT, JR., County Attorney,Natrona County, Wyoming.

For the Intervenor Town of Mills, Wyoming (Mills): WILLIAM C. LUBEN, WALLACE E.TREMBATH, ifi and ROBERT J. HAND, ofHand & Hand, Casper, Wyoming.

For the Intervenor Powder River Basin Resource Council (PRBRC), SHANNON ANDERSON,General Counsel, Sheridan, Wyoming.

For the Intervenor Town of Midwest, Wyoming (Midwest): WILLIAM C. LJJBEN, WALLACEB. TREMBATH, ifi, and ROBERT J. HAND, of Hand & Hand, Casper, Wyoming.

For the Intervenor United States Department of Energy (LJSDOE): STEVEN PORTER, AssistantGeneral Counsel, Washington, D.C.

Members of the public appearingpro se at the June 2, 2011, public comment hearing:

LINDA BERGERON, Casper, WyomingPAUL BERTOGLIO, Mayor, City of Casper, WyomingCECIL HARRIS, Casper, WyomingR.C. JOHNSON, Casper, WyomingMARION LOOMIS, Representing Wyoming Mining AssociationCLIF MCCRADY, Representing Community Action Partnership Natrona CountySTAN MCINROY, Casper, WyomingALLEN MOTT, Casper, WyomingROY O’BRIEN, Midwest, WyomingDICK SADLER, Casper, WyomingPAT SWEENEY, Casper, WyomingJASON THORNOCK, Cokeville, WyomingDON WOLCOTT, Casper, Wyoming

HEARD BEFORE

Chairman ALAN B. MIMERDeputy Chairman STEVE OXLEY

Commissioner KATHLEEN A. “CINDY” LEWIS

DAV]D J. LUCERO, Assistant Secretary,Presiding pursuant to a Special Order of the Commission

MEMORANDUM OPINION, FINDINGS AND ORDER APPROVING STIPULATION(Issued September 22, 2011)

This matter is before the Wyoming Public Service Commission (Commission) upon the

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application of Rocky Mountain Power for authority to increase its retail electric utility servicerates in Wyoming by approximately $97.9 million per year, the testimony of the publicwitnesses, and on the interventions of the OCA, WIEC, QEP, lnterwest, Cimarex, the UWUALocal 127 (the Union), Senator Cale Case (Senator Case), AARP, the Towns of Midwest, Mills,and Bar Nunn, Wyoming, the City of Casper, Wyoming, Natrona County, Wyoming,’ theUSDOE, KMIGT, Granite Peak, and the PRBRC.

The Commission, having reviewed the Stzpulation and Agreement (Stipulation), theapplication and subsequent modifications to the original application and attached exhibits, theevidence adduced at the public hearing, its files regarding Rocky Mountain Power, applicableWyoming utility law, and otherwise being fully advised in the premises, FINDS andCONCLUDES:

Procedural Matters

1. On November 22, 2010, Rocky Mountain Power submitted an application,together with revised tariff sheets and the pre-filed testimony and exhibits from eighteenwitnesses, requesting authority to increase its retail electric utility service rates in Wyomingapproximately $97.9 million per annum or an average overall increase of 17.3%. RockyMountain Power asked the Commission to reset its Wyoming revenue requirement in this caseusing a forecasted or future test period starting with historical data for the 12 months ending June30, 2010, with a forecasted or future test period consisting of the 12 month time period endingDecember 31, 2011.

2. On November 29, 2010, the Commission issued its Suspension Order suspendingthe proposed rates for investigation and further action for the initial six-month period provided inW.S. § 37-3-106(c) which commences after the 30-day notice term provided in subsection (b)thereof.

3. On December 1, 2010, the Commission issued a Notice of Application (as thecontext requires, the 2010 General Rate Case) containing a deadline of January 3, 2011, for filingrequests for intervention with the Commission. The Notice ofApplication was published onceper week for two consecutive weeks in the Glenrock Independent, the Thermopolis IndependentRecord, the Casper Star-Tribune, the Green River Star, the Northern Wyoming Daily News inWorland, the Riverton Ranger, the Kemmerer Gazette, the Daily Rocket-Miner in Rock Springs,the Pinedale Roundup, the Uinta County Herald in Evanston, the Cody Enterprise, the BuffaloBulletin, the Douglas Budget, the Lovell Chronicle, the Lander Journal, and the DailyBoomerang in Laramie. A public service announcement with regard to the case was broadcaston radio five times per week for two consecutive weeks on KTWO in Casper, KTRZ in Riverton,KLDI in Laramie, KRKK in Rock Springs, KKTY in Douglas, KOVE in Lander, KBBS inBuffalo, KEVA in Evanston, KTHE in Thermopolis, KWOR-AM in Worland, KPIN in Pinedale,KMER in Kemmerer, and KODI in Cody.

4. Thereafter, the following parties were granted intervention status by order of the

1 As the context requires, the Towns of Midwest, Mills, and Bar Nunn, Wyoming, the City of Casper, Wyoming,and Natrona County, Wyoming, are referred to collectively as the Governmental Intervenors.

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Commission: WIEC, QEP, Cimarex, Interwest, AARP, Casper, Mills, Bar Nunn, Midwest,Natrona County, Granite Peak, KMIGT, the Union, PRBRC, Senator Cale Case and the USDOE.Pursuant to Wyoming statute, the OCA also participated as an intervenor. Upon attaining partystatus, each intervenor became a party for all purposes in this proceeding. The Sierra Club’slate-filed Petition to Intervene (Petition) was denied by Commission order based on the findingthat the Sierra Club had failed to demonstrate “good cause” to support its late-filed Petition andgranting the late-filed Petition was not in the public interest. The Commission observed that theSierra Club could participate meaningfully in conjunction with the PRBRC, as it was afready anintervenor.

5. On January 10, 2011, the Commission issued its Special Order Authorizing OneCommissioner and/or Hearing Examiner to Conduct Public Hearing as approved at theDecember 6, 2010, open meeting.

6. On February 2, 2011, the Commission issued its Scheduling Order setting aprocedural schedule and public hearing in this case.

7. On April 11, 2011, the OCA filed testimony and exhibits supporting a return onequity of 9.5% and an overall proposed rate increase of approximately $67.8 million. The OCAalso proposed revisions to the Company’s class cost of service analysis and an alternative, three-tier inclining block rate for residential customers.

8. On April 11, 2011, WIEC filed testimony and exhibits supporting, inter alia, areturn on equity of 9.75% and an overall rate increase of approximately $14.7 million on anhistorical test year basis or approximately $30.2 million on a forecast test year basis.

9. On April 11, 2011, PRBRC, Cimarex, KMIGT and QEP filed testimony regardingthe prudence of environmental upgrades the Company has made at certain of its generationplants.

10. On April 21, 2011, Granite Peak, the Governmental Intervenors and AARP filedtestimony regarding capacity, reliability and rate impact concerns.

11. On May 6, 2011, the Company filed rebuttal testimony updating certain costs andaddressing issues raised in Intervenor testimony filed on April 11, 2011. The Company adopteda number of adjustments related to issues identified by Intervenors, reducing the overallrequested rate increase from $97.9 million to $80.1 million, subject to the acceptance of theproposed treatment of the net power cost update discussed by Company witness Greg Duvall. Inaddition, WIEC, OCA, USDOE, Cimarex, QEP, and Kinder Morgan filed cross-answertestimony addressing issues raised in the testimony of other Intervenors filed on April 11, 2011.The Union filed rebuttal testimony on May 12, 2011.

12. On May 16, 2011, the Commission issued a Procedural Notice and Order SettingMultiple Hearings (Notice), which was published once per week for two consecutive weeks inthe Glenrock Independent, the Thermopolis Independent Record, the Casper Star-Tribune, theGreen River Star, the Northern Wyoming Daily News in Worland, the Riverton Ranger, the


Kemmerer Gazette, the Daily Rocket-Miner in Rock Springs, the Pinedale Roundup, the UintaCounty Herald in Evanston, the Cody Enterprise, the Buffalo Bulletin, the Douglas Budget, theLovell Chronicle, the Lander Journal, and the Daily Boomerang in Laramie. A public serviceannouncement with regard to the case was broadcast on radio five times per week for twoconsecutive weeks on KTWO in Casper, KTRZ in Riverton, KLDI in Laraniie, KRKK in RockSprings, KKTY in Douglas, KOVE in Lander, KBBS in Buffalo, KEVA in Evanston, KTHE inThermopolis, KWOR-AM in Worland, KP1N in Pinedale, KMER in Kemmerer, and KODI inCody. The Notice scheduled a public comment hearing for June 2, 2011, in Casper and thepublic contested rate case hearing to commence on June 20, 2011, in Cheyenne.

13. On June 2, 2011, the Commission held the noticed public comment hearing inCasper, Wyoming. At the hearing, the Company presented testimony by Paul Radakovich, VicePresident of Operations, and David Mosier, Regulatory Affairs Manager. The comments of thepublic witnesses are summarized, infra.

14. The Commission issued its second Suspension Order in the general rate case onJune 3, 2011, suspending the application pending further investigation for the final three-monthperiod allowed by W.S. § 37-3-106(c).

15. On June 6, 2011, Rocky Mountain Power, OCA, WIEC, QEP, Cimarex,Jnterwest, AARP, Casper, Mills, Bar Nunn, Midwest, Natrona County, Granite Peak, KMIGT,the Union, and PRBRC filed a Stzpulation, which was presented to the Commission as aresolution of all outstanding issues related to this case, as more fully described therein and in thisOrder.

16. On June 17, 2011, Rocky Mountain Power filed a written response to questionsraised by Jason Thomock at the June 2, 2011, public comment hearing regarding the validity ofan easement across his neighbor’s property and whether the Company has a contractual duty toconstruct a line extension across that neighbor’s property to provide power to Thornock’ sirrigation pivot, when the validity of the easement was in question and the subject of litigation.

17. Pursuant to the orders of the Commission and due notice, the public contested ratecase hearing in this matter was held on June 20-2 1, 2011, in Cheyenne. The Company, WIEC,QEP, Cimarex, Interwest, AARP, the Governmental Jntervenors, Granite Peak, K]\’IIGT,PRBRC, and the USDOE appeared in support of the Stipulation. Senator Case and the Union didnot appear. At the end of the public contested rate case hearing, the Commission closed therecord and held public deliberations pursuant to W.S. § 16-4-403. The Commission thereuponapproved the Stipulation, as discussed more fully below, the same to be effective upon theissuance of the Commission’s final order.

18. On July 13, 2011, Rocky Mountain Power filed a Rawlins Wyoming AreaTransmission Substations Audit Report (Report). The Report was filed as a result of acommitment by the Company made by Paul Radakovich, Operations Vice President for RockyMountain Power, at the June 2, 2011, public comment hearing.


Summary of Evidence at the June 2, 2011, Public Comment Hearing

19. For Rocky Mountain Power, David M. Mosier, Wyoming Regulatory AffairsManager, presented an overview of the case and described the fundamental reasons for theCompany’s filing, including the need for additional generation, transmission and distributionfacilities to serve the growing demand for electricity in Wyoming. Mosier also noted that,despite the increase, Rocky Mountain Power’s rates remained among the lowest in Wyoming andthe country.

20. Paul K. Radakovich, the Company’s Vice President of Operations, discussedservice quality and reliability issues, and the multi-year service quality improvement plan theCompany is implementing in the Natrona County area.

21. AARP, Casper, OCA, WIEC, Granite Peak, and Cimarex also providedcomments. Mayor Paul Bertoglio, offered comments of behalf of the City of Casper, discussingthe City’s experience and concerns about service reliability. Mayor Bertoglio stated there havebeen significant increases in electric outages in the Casper and Natrona County areas over thepast three years. Mayor Bertoglio stated these outages are not just an issue of service reliabilityfor the City; there is also a concern for the public safety because power outages affect trafficsignals, communications between law enforcement personnel and the water treatment plant.(Transcript of the June 2, 2011, public comment hearing, hereinafter, Comment Tr., pp. 24-25.)In addition, the Commission received numerous public comments, including comments on theCompany’s line extension policy, service reliability, the need for the continued use of coal-firedgeneration, the Company’s budget and projected future rate increases, the calculation of demandcharges, the impact of the increases on low income customers, and a request that the rate increasebe explained in language a layman can understand.

22. Jason Thomock of Cokeville, Wyoming, provided comments regarding thevalidity of an easement across his neighbor’s property and whether the Company has acontractual duty to construct a line extension across that neighbor’s property to provide power toThomock’s irrigation pivot. Thornock stated that delays in the construction of the power linedue to questions regarding the validity of the easement and Rocky Mountain Power’s duty toconstruct the line extension forced him to use an alternative line route at a cost to him of $50,000in order to get power to his pivot inigation system. Thornock expressed his dissatisfaction overthe manner in which the matter was handled, stating the Company should be required toreimburse him for the expenses he incurred. (Comment Tr., pp. 42-50.)

23. Several customers complained of service reliability. Dick Sadler spoke of thenumerous times he lost power and the difficulties he experienced getting the Company to restorepower in a timely manner. (Comment Tr., pp. 51-56.) Roy O’Brien, a retired employee of RockyMountain Power from Midwest, spoke of the numerous outages he experienced and the lack ofCompany personnel in the area to restore power in a timely manner. O’Brien stated the closestRocky Mountain Power employee available at the time to deal with outages was located inBuffalo. (Comment Tr., p. 68.)


24. Marion Loomis, Executive Director of the Wyoming Mining Association, spokeof the need for the continued use of coal-fired plants in Wyoming. He discussed the use of coal,coal-fired power plants, and their benefits to Wyoming, including reducing the cost of electricityto Wyoming rate payers. He said the states with the largest percentage of their electricity supplycoming from coal generation have the lowest electricity prices. Loomis noted that Wyoming hasone of the lowest prices for electricity in the nation and one of the highest percentages of coalgeneration, stating that 88% of the electricity in Wyoming is generated by coal at an average costof 6.2 cents per kilowatt hour. Loomis urged the Commission to consider the benefits providedto Wyoming rate payers because of the reliability and affordability of coal-generated electricityas well as the revenues generated by Wyoming coal production. He concluded by stating thatWyoming should continue to support coal mines, coal-fired power plants and encourage thecontinued reliable, affordable generation of electricity from coal for the benefit of the citizens ofWyoming. (Comment Tr., pp. 57-62.)

25. Stan Mclnroy of Casper questioned where the money generated from theproposed increase would go, how much other states pay for the electricity generated in Wyomingand the cost to Wyoming rate payers for the construction of transmission lines to send theelectricity generated in Wyoming to other states. He also asked to see a copy of RockyMountain Power’s budget. Mclnroy questioned the 10.5% annual rate of return for RockyMountain Power and why rate payers are required to pay for Rocky Mountain Power’sinvestment in new plant, and argued that the income generated from the new customers shouldpay for those investments. (Comment Tr., pp. 63-66.)

26. Pat Sweeney, owner of several businesses in Casper, commented on the demandcharge and asked the Commission to approve the Company’s requested rate increase buteliminate the demand charge. Sweeney stated the demand charge doubles his businesses’ ratesand is nothing more than a double tax. He also discussed his frustration with having to removeexterior lights from a power pole which had been in place for 40 years in front of one of hisbusinesses, stating Rocky Mountain Power claimed it did not own the light fixture. Sweeneystated the lighting was removed and wall lamps were installed on his business at his expense toprovide light to his business parking lot. (Comment Tr., p. 69-75.)

27. Other customers offering comments discussed the financial impact the proposedrate increase would have on customers, particularly low income customers and those on fixedincomes. Clif McCrady, a representative of Community Action Partnership in Natrona County,discussed the financial difficulties the proposed increase will place on low income families,stating Rocky Mountain Power’s customers do not have a choice for their electricity needs.(Comment Tr., pp. 77-80.) Cecil Harris (Comment Tr., pp. 92-93), Don Wolcott (Comment Tr.,p. 96) and Allen Mott (Comment Tr., pp. 98-99), all from Casper, discussed the affect theproposed rate increase would have on retirees, those living on fixed incomes, and those living ator below poverty level. Customers expressed concern for those who have received no cost ofliving increases to cover the costs for food, housing and transportation, as well as those who havenot seen an increase in their Medicare benefits.


28. Linda Bergeron of Casper questioned how RIvIP’s billing structure worked andencouraged the use of Wyoming’s natural resources, such as coal and natural gas. (CommentTr., p. 83.)

29. Mrs. R.C. Johnson of Casper questioned why RMP does not keep a list ofinventory [i] demonstrating the Company’s ownership of such things as lights and power lines,differentiating them from customer-owned facilities or [ii] why Rocky Mountain Power does notkeep adequate documentation of the conditions and status of power lines. She also questionedhow Rocky Mountain Power determines growth. She stated that she had read in the newspaperthat Wyoming is only 3% of the customer base of Rocky Mountain Power, and questioned whyWyoming pays 16% of the costs for wind farms rather than 3% of the cost. Johnson alsoquestioned the demand charge and what portion of the increase is equated to a customer’sincome and suggested that information be presented using simple, clear charts that demonstratewhat customers are paying for. She said “[t]he stuff you’re tailcing about is not.. .rocket science”and discussed the need for transparency in how the Company operates. In her opinion, RockyMountain Power needs to explain issues not in “professional [electric utility industry] jargon”but “in very simple, common-sense tenus so that everyone in the general public can understand.”Johnson suggested rate case information should come from reliable sources such as theCommission and then released to the public to be viewed in a clear and direct manner. Shestated that inaccurate information should be corrected and provided to the public clearly anddirectly such as on the Commission’s website or in the newspapers. (Comment Tr., pp. 85-9 1.)

Summary of Evidence at the June 20-21, 2011 Public Contested Rate Case BearingRocky Mountain Power Prefiled and Rebuttal Testimony

30. A. Richard Waije, President of Rocky Mountain Power, prefiled direct testimonyand exhibits in support of the Company’s application. (RMP Exhibit 1.) In his preffledtestimony, Waije provided an overview of the Company’s 2010 Wyoming general rate case,stating the requested increase used an historical test year ended June 30, 2010, as the base periodfor the case development, with adjustments to reflect anticipated cost levels through the 12-month test period ending December 31, 2011 (the test period). He discussed [iJ the need for arate increase; [ii] details of the requested increase; [iii] Rocky Mountain Power’s financialchallenges and risks, including financing needs and credit ratings; [iv] the major cost driversunderlying the increase, including, principally, capital investment, net power costs and loadgrowth; [v] the Company’s efforts to control costs while maintaining reliable service andcustomer satisfaction; [vi] pricing impacts on customers from the proposed increase; and [vii]opportunities available to customers to control their energy use and mitigate the impacts of thisprice increase through Company-offered energy efficiency programs.

31. Bruce N. Williams, Vice President and Treasurer for Rocky Mountain Power,prefiled direct and rebuttal testimony and exhibits in support of the Company’s originalapplication. (RMP Exhibit 2.) In his prefiled testimony Williams [iJ provided an overview ofCompany financing, [ii] discussed the planned amounts of common equity, debt and preferredstock to be included in the Company’s proposed capital structure, and [iii] analyzed theembedded cost of debt and preferred stock supporting PacifiCorp’s electric operations inWyoming for the test period. Williams’ analyses covered the test period, and determined thecapital structure and costs of long-term debt and preferred stock using an average of the five

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quarterly ending balances spanning the test period. Williams proposed an overall cost of capitalof 8.36%, based on long term debt costs of 5.82%; preferred stock cost of 5.43%; and a return oncommon equity of 10.6% as recommended by Samuel Hadaway. (RMP Exhibit 2, p. 2.) In hisrebuttal testimony, Williams responded to the capital structure recommendations of WIECwitness Michael Gorman and provided updates to capital structure and overall cost of capitalinformation that resulted in a reduction to the Company’s overall revenue requirement and rateincrease request in this docket. Based upon updating the Company’s financing plans due to theenactment of bonus depreciation and cancellation of a plant acquisition, Williams updated thecost of long-term debt to 5.8 1%; preferred stock remained at 5.43%; and a recommended returnon common equity of 10.50%; for an overall cost of capital of 8.26%. Williams also explainedhis disagreements with Gorman’s assessments and analysis, arguing Gorman’s results andrecommendations were seriously flawed, misleading and should be rejected by the Commission.

32. Samuel C. Hadaway, a Principal in FINANCO, Inc., Financial Consultant,prefiled direct and rebuttal testimony and exhibits on behalf of the Company. (Rocky MountainPower Exhibit 3.) In his prefiled testimony, Hadaway recommended a 10.6% return on commonequity capital (ROE) based on his discounted cash flow (DCF) analysis which indicated areasonable ROE range of 10.3% to 10.8%. Hadaway stated, although he used a risk premiumanalysis which indicated a range of only 9.73% to 9.9 1%, he did not rely on those results due tocurrent market conditions. Hadaway’s prefiled testimony discussed [iJ how his analysis wasstructured; [ii] the various methods he used for estimating the cost of equity includingcomparable earnings methods, equity risk premium methods and his DCF modeling; [iii] hisreview of recent capital market conditions and industry factors that should be reflected in thecost of capital; [iv] the cost of equity capital for Rocky Mountain Power; and [v] his quantitativestudies of the cost of equity capital for the Company, including discussion of the details andresults of his analyses. Hadaway’s analyses used three versions of the DCF model applied to 23comparable companies. He also applied various equity risk premium models and reviewedprojected economic conditions and projected capital costs for the coming year. In his rebuttaltestimony, Hadaway addressed the cost of common equity and ROE recommendations of theOCA witness Freeman and WIEC’s witness Gorman. Freeman recommended a ROE of 9.5%;Gorman recommended a ROE of 9.75%; and, based on his updated ROE analysis, Hadawayrecommended a revised ROE of 10.50%.

33. Brian S. Dickman, Rocky Mountain Power’s Manager of Revenue Requirement,prefiled direct and rebuttal testimony in support of the Company’s application. (RMP Exhibit 4.)Dickman’s direct testimony addressed the calculation of the Wyoming-allocated revenuerequirement and revenue increase requested in this case. He testified that the two main driversfor the proposed rate increase are capital investment and net power costs. His direct testimonyincluded: [i] support for the calculation of the $97.9 million overall revenue increase requestedby the Company to recover its total Wyoming revenue requirement of $664.7 million per year;[ii] support for the test period and related average rate base calculation for the test period; [iii] anexplanation of the 2010 Multi-State Protocol inter-jurisdictional allocation methodology utilizedto compute the requested rate increase and the current procedure before the Commissionaddressing inter-jurisdictional allocations; [iv] support for property and liability insuranceexpense from MidAmerican Energy Holding Company (MEHC) classified as administrativeservices; [v] an explanation of the treatment of revenue from the sale of RECs; [vi] an


explanation of the process used by the Company to prepare the Wyoming results of operationsfor the test period; and [vii] a detailed explanation of the normalizing adjustments included inthis case. In his prefiled direct testimony, Dickman stated that, without a rate increase, theCompany will earn an overall rate of return of 5.0% in Wyoming during the test period, which isless than the current ROR of 8.33% authorized in the previous (Sub 352) rate case, and less thanthe 8.36% requested in this case. Dickman stated the Company used a test year endingDecember 31, 2011, using historical data for the 12 months ended June 2010, as a base. Hestated the Company chose the year ending December 31, 2011, as the test period because this testperiod helps to satisfy the need for adequate recovery of prudently incurred costs and reflects thebest estimates of conditions likely to pertain during the time the proposed rates will be in effect.In his rebuttal testimony, Dickman addressed issues raised by OCA witness Parrish and W1ECwitnesses Higgins, Peterson and Gorman. He presented a revised calculation of the Company’sWyoming-allocated revenue requirement and an updated revenue request. Diclcman’srecalculated revenue requirement for the test year reduced the Company’s overall request from$97.9 million to $80.1 million. His rebuttal testimony also addressed the Company’s oppositionto certain adjustments proposed by the Intervenors that were not incorporated into the revisedresults.

34. Erich D. Wilson, Director of Human Resources for the Company, prefiled directand rebuttal testimony and exhibits which provided an overview and support for the costsassociated with the compensation and benefit plans provided to Company employees. (RMPExhibit 5.) Wilson discussed the base pay, annual incentive, pension and healthcare benefitplans, and discussed steps Rocky Mountain Power has undertaken to control the costs associatedwith employee benefits plans. Wilson stated these plans are designed to allow the Company toattract and retain employees. In his rebuttal testimony, Wilson explained why the Commissionshould reject certain labor-related adjustments proposed by AARP witness Brockway, WIECwitness Higgins and OCA witness Parrish.

35. John A. Cupparo, Vice President of Transmission for PacifiCorp, prefiled directand rebuttal testimony and exhibits in support of Rocky Mountain Power’s application and insupport of the inclusion of the company’s investment in Phase II of the Populus to Terminaltransmission project (the Project), which is part of Rocky Mountain Power’s Energy Gatewayplan. (RMP Exhibit 6.) He stated the Project will benefit Wyoming and the Company as it willenhance the reliability of the Company’s transmission system and improve transfer capabilitywithin the transmission system. The Project will help the Company including the ability toobtain increased reserve sharing benefits, and provide necessary incremental transmissioncapacity —the key to unlocking the high quality generation resource areas in Wyoming. Cupparorebutted the direct testimony of WIEC witness Dennis Peseau regarding the Project, arguing thatthe Project is fully used and useful based on prudent utility planning for reliability and the needto meet the current and future electrical needs of the Company’s customers. Regarding Peseau’ssuggestion that 50% of the Project is not currently used and useful, Cupparo responded, interalia, that the Populus to Terminal line was fully energized and providing the system withreliability benefits and increased transfer capacity. Cupparo testified that Peseau’s rationale wasoverly simplistic and plainly not applicable to such an investment (e.g., it would make littleeconomic or operational sense to build a line capable only of providing 50% of the capacityexpected to be needed in the future).

10 Docket No. 20000-384-ER-b

36. Darrell T. Gerrard, Vice President of Transmission System Planning forPacifiCorp, prefiled direct and rebuttal testimony and exhibits in support of the Company’sapplication. (RMP Exhibit 7.) His prefiled direct testimony provided additional detail andtechnical information on the Company’s decision to build the double-circuit 345 kV Phase II ofthe Project. With the completion of the Populus to Terminal portion of the Populus to BenLomond project, the Company expects the total investment in the Populus to Ben Lomondproject will be $553.8 million. According to Gerrard, the transmission line segment will [ijincrease the overall capacity in the existing transmission system between Southeast Idaho andNorthern Utah; [ii] meet the immediate need to improve system reliability in the area; [iii]improve the Company’s ability to perform maintenance on transmission facilities betweenPopulus and Terminal by having alternative transmission paths that allow facilities to be takenoff-line and maintained with no loss of service; [iv] integrate with future Energy Gatewaysegments to increase transfer capability between PacifiCorp’s east and west control areas inorder to balance generating resources and loads, enable commercial energy purchases or sales,while allowing integration of new renewable generation resources (many of which are located inWyoming); [v} provide PacifiCorp with more options and greater flexibility when planningfuture resources in the Company’s current and future IRPs to meet customers’ growing energydemands (and current and future energy requirements mandated by state and federal regulation);[vi] facilitate the integration of potential new energy resources in Wyoming and supporteconomic development; and [vii] in the long-term, provide an incremental increase intransmission capacity and reliability benefits for future Energy Gateway transmission segmentsplanned between Wyoming, Idaho, Utah, Oregon and Washington. Gerrard also providedtestimony to rebut the direct testimony of Peseau regarding the Project.

37. Dean S. Brockbank, PacifiCorp’s Vice President and General Counsel, prefileddirect and rebuttal testimony and exhibits in support of the Company’s application. (Rlv[PExhibit 8.) Tn his direct testimony, Brockbank explained the process involved in obtaining newfederal licenses for hydroelectric projects, providing context for his explanation of the KlamathHydroelectric Project (Kiamath Project) and the settlement of issues related to the relicensingproceeding. He stated the Company was seeking $73.76 million on a system-wide basis torecover the relicensing and settlement costs. Brockbank stated the Company’s relicensing andsettlement efforts have achieved an outcome through the Klamath Hydroelectric SettlementAgreement (KHSA) that provides protections to Wyoming customers from costs and risksrelated to continued relicensing of the Kiamath Project, as well as the costs and risks involved inpotential facilities removal. In his rebuttal testimony, Brockbank responded to WIEC witnessHiggins’ argument that the Commission should deny the Company’s request to adjust thedepreciation lives of the Kiamath Project assets on the basis that [i] federal legislation endorsingthe KHSA has yet to be passed and [ii] up to $250 million in funding from the State of Californiafor dam removal has yet to be approved.

38. Chad A. Teply, President of PacifiCorp Energy, prefiled direct and rebuttaltestimony and exhibits in support of Rocky Mountain Power’s application. (RMP Exhibit 9.)Teply’s direct testimony provided information seeking to demonstrate the prudence of capitalinvestments in pollution control equipment, additional generation plant, and mining and hydroprojects being placed in service during the test period. Teply stated that investments in pollution


control equipment are required to meet the Regional Haze Rules adopted in 2005 by the U.S.Environmental Protection Agency (EPA), which trigger Best Available Retrofit Technology(BART) reviews, state implementation plans and permitting processes. He stated the pollutioncontrol equipment investments are primarily designed to reduce the sulfur dioxide (SO2),nitrogen oxides (NO), mercury (Hg) and particulate matter (PM) emissions from the retrofittedfacilities, as required by current and anticipated government regulation. According to Teply,generation plant turbine upgrade investments enhance the Company’s overall generationcapability and cycle efficiency without increasing the large thermal units. Teply’s directtestimony described the pollution control investments and costs for the Naughton Units I and 2scrubber projects; the Wyodak Plant stand-alone bag house project; the Huntington Unit 1 powerplant bag house conversion and scrubber upgrade project; the Hunter Unit 2 bag houseconversion scrubber upgrade project; and the Jim Bridger Unit 3 scrubber update project. Teplystated customers directly benefit from the installation of the pollution control equipment throughlow-cost generation produced at the facilities and environmental improvements resulting inclearer air. In his rebuttal testimony, Teply responded to the direct testimony of PRBRCwithesses Steinhurst and Fisher, and Goins’ direct testimony for Cimarex, KMIGT and QEP,regarding the prudence of the Company’s pollution control expenditures for coal-fired generationplants. Teply’s rebuttal testimony supported the prudence of Rocky Mountain Power’sexpenditures for pollution control investments and the prudence of its compliance with presentand future air pollution requirements.

39. Howard M. Ellis, President of Enviroplan Consulting, submitted rebuttaltestimony and exhibits in response to the direct testimony of Steinhurst, Fisher, and Goinsregarding the prudence of the Company’s pollution control expenditures for coal-fired generationplants. (RMP Exhibit 10.) Ellis concluded, inter alia, that Rocky Mountain Power exercisedprudent engineering judgment regarding the costs it incurred in complying with existing andfuture air pollution control requirements, and concluded its air pollution control investmentswere reasonable, prudent and mandatory.

40. Cathy S. Woolums, Senior Vice President of Environmental Service and ChiefEnvironmental Counsel for MEHC, prefiled direct and rebuttal testimony and exhibits (RMPExhibit 11) in support of the Company’s application and in response to the direct testimony ofSteinhurst, Fisher, and Goins regarding the prudence of the Company’s pollution controlexpenditures for coal-fired generation plants, and in support of the processes the Company usedto identif’ environmental policy and compliance drivers that influenced the installation of theemission controls. Woolums discussed, inter alia, the Company’s consideration of futureenvironmental requirements when undertaking the emission reduction projects. She discussedhow the Company complies with existing permit and regulatory requirements for wastemanagement activities and the Company’s activities in achieving compliance with futurerequirements.

41. Douglas N. Bemiion, Rocky Mountain Power’s Vice President of EngineeringServices and Capital Investment, prefiled direct and rebuttal testimony and exhibits whichexplained and supported the transmission and distribution (T&D) capital expenditures includedin the rate case (with the exception of the large main grid projects). (RIVIP Exhibit 12.) Bennionstated the Company’s capital investment in T&D will benefit customers by improving service

12 Docket No. 20000-384-ER-b

quality, reliability and the delivery of power to meet current and new customer loadrequirements. Bennion’s rebuttal testimony addressed issues and concerns raised by GranitePeak witness Trembath in direct testimony, OCA witness Freeman’s direct testimony, and thedirect testimony of Myers, Trembath and Gromko filed on behalf of the GovernmentalIntervenors, and the prefiled direct testimony of AARP witness Brockway. Bermion’s rebuttaltestimony responded to the Intervenor witnesses’ concerns regarding reliability and capacity,particularly in the Casper area, and discussed the multi-year process currently underway toenhance the electricity infrastructure in and around the Casper area.

42. F. Robert Stewart, Regulatory Consultant, Customer & Regulatory Liaison inRocky Mountain Power’s Customer Service Department, prefiled direct and rebuttal testimonyand exhibits addressing changes to the Company’s Rule 12 — Line Extensions, Rate Schedule 2and the various lighting rate schedules. (RMP Exhibit 13.) Stewart stated the Company was notproposing to change the extension allowance for residential or non-residential customer classes.He discussed the concerns expressed by the focus groups, which included representatives of theGovernmental Tntervenors, developers and economic development representatives, regarding,inter alia, the timeliness of the Company’s response to feasibility studies for economicdevelopment siting purposes concerning large prospective loads. He stated Rocky MountainPower was not proposing to make any tariff changes to address this issue but is committed toimproving the timeliness of delivery and the quality of answers related to project sitingrequirements. He discussed the Company’s various proposals to its Rule 12, Line ExtensionPolicy, in response to the focus group meetings. The changes include, inter alia, [i] clarifyingrevisions to Sheet No. R12-2, Section I.F.; [ii] changes to Sheet R12-3, Section I.J. to increasethe number of refunds; [iii] new language in Sheet No. R12-12, Section TV.B; and [iv] changesto the Applicant Built Line section of the Line Extension tariff at Sheet Nos. R12-15 and R12-16,Sections V.A.5 and V.A.1O. He also discussed other changes the Company is proposing to itsLine Extension Policy which include, inter alia, changes to Section I.J. Refunds, RemoteResidential Customers, Sheet No. R12-6, Section ll.C. 1; Sheet No. 12R-8, Section ifi; Sheet No.R12-9, Section IIJB.2; Sheet Nos. R12-8 through R12-1 1. Tn his rebuttal testimony Stewartaddressed the line extension policy and tariff issues raised by Trembath for Granite Peak, and theGovernmental Intervenors.

43. Jeffery W. Baumgarner, Director of Demand-Side Management for RockyMountain Power, prefiled direct and rebuttal testimony that provided responses to theCommission’s Order in Sub 352 addressing the creation of the Company’s demand sidemanagement (DSM) programs and discussing the status of its current resource planning withrespect to load control. (RMP Exhibit 14.) He described the process for identifying DSMresources. The Company relies on the independent third party results of specific service territoryConservation Potential Assessment (Potential Assessment) studies to identify energy efficienciesand load control resources. Baumgamer testified that energy efficiency and load control supplycurves are treated — and modeled — like any other supply-side resource in the Company’s IRP.Baumgarner’s prefiled direct testimony also, inter alia, discussed the IRP process and the energyefficiency and load control products considered by the Company in the IRP. In his rebuttaltestimony, Baumgamer spoke to OCA witness Freeman’s contention that the Company failed torespond to paragraph 179 of the Commission Order in Sub 352 which directed the Company toaddress creation of a demand response market. Baumgarner stated that the Company believes it

13 Docket No. 20000-384-ER-b

has thoroughly responded to the Commission’s Order in Sub 352 through its work with thecollaborative, implementation of, and revisions to, Schedule 73, and through his explanation inhis direct testimony regarding the manner in which the Company leverages demand responsestrategies to assist in managing customer usage.

44. Steven Walton, Independent Consultant specializing in electric powertransmission planning and policy, filed rebuttal testimony and exhibits (RMP Exhibit 15)rebutting the prefiled direct testimony of WIEC witness Peseau regarding the Company’sPopulus to Terminal Transmission Project, particularly Peseau’s assertion that the Populus toTerminal Line is only 50% used and useful because excess capacity was built into the line.Walton argued, inter alia, that the moment the Populus to Terminal line was energized, its fullcapacity was available to the system to provide reliable service to customers. He explained thatwhen a transmission line is added, it becomes a fully integrated part of the system, and istherefore fully used and useful in the provision of reliable transmission service from the date thatit is energized. Walton said that the Populus to Terminal line was not overbuilt, it would nothave been prudent for the Company to build a lesser facility because projects must be built tohave the flexibility to meet expected future conditions. Regarding Peseau’s recommendation todisallow recovery on 50% of the line, Walton stated Peseau’s recommendation should berejected because it ignores the realities of planning, building and operating transmission systems.He stated the Company prudently planned and designed the line in the public interest. Becausethe full capacity of the Populus to Terminal line was available for reliable operation of theinterconnected system from the moment it was placed in service, it is currently benefitingWyoming customers, regardless of the completion of the rest of the Energy Gateway projects.

45. Peter C. Eelkema, Rocky Mountain Power Lead/Senior Consultant, Load andRevenue Forecasting, prefiled direct testimony (RMP Exhibit 16) describing the Company’smethods for developing the forecasts of the number of customers, kilowatt-hour sales at themeter, system loads and system peak loads at the system input levels, and the number of bills forthe 12-month period ending December 31, 2011. These data are used in calculating Wyomingnet power costs, revenue requirements, and cost allocation factors to design rates and to allocatecosts and revenue responsibility among the customer classes. Eelkema stated the Company hasdeveloped a forecast ofbills and kilowatt-hour sales by rate schedule for Wyoming.

46. C. Craig Paice, Regulatory Consultant in the Regulation Department for RockyMountain Power, prefiled direct and rebuttal testimony and exhibits (RMP Exhibit 17) in whichhe presented and discussed the Company’s Embedded Cost of Service Study for Wyoming basedon the 12-month forecast test period ending December 31, 2011. He stated the class cost ofservice study employs the Revised Protocol Methodology used in the 2009 general rate case. Inhis rebuttal testimony, Paice responded to the direct testimony of WIEC witness Baron and OCAwitness Backofen regarding cost of service issues and presented the Company’s revised 2011Class Cost of Service Study based on the twelve month forecasted test period ending December31, 2011, which was updated to reflect Wyoming results of operations based on the 2010Protocol. Paice provided a table illustrating the cost of service results and their impacts on thevarious customer classes based on the Company’s original cost of service study and those basedon the WIEC and OCA proposals. (RMP Exhibit 17, Rebuttal Testimony p. 17.)

14 Docket No. 20000-384-ER-b

47. William R. Griffith, Director, Pricing, Cost of Service and Regulatory Operationsfor Rocky Mountain Power, prefiled direct and rebuttal testimony and exhibits in support of theCompany’s application. (RMP Exhibit 18.) Tn his direct testimony, Griffith presented anddiscussed the Company’s proposed tariffs and rate spread for a rate increase of $97.9 million or17.27% per year. He stated that the proposed rate increase was allocated to the various customerclasses in accordance with the Stipulation entered into and approved by the Commission inDocket No. 20000-ER-02-184 (Sub 184) which provided that prices charged to the variouscustomer classes would be designed to collect between 99% and 101% of their respective costsof service. This rate spread methodology has been utilized in subsequent rate cases including themost recent 2009 general rate case. Griffith stated the Company’s rate design methodologyproposes rates that continue with the process established in Sub 184 to move towards recoveringcosts by demand, energy and basic charge rate elements for all schedules except Schedule 40.Griffith stated the Company was not proposing any rate design changes for the Residential Class,Schedule 2. However, the Company was proposing an increase in the Residential Monthly BasicCharge from $20 to $24 a month. Griffith also provided testimony addressing the proposed ratedesigns for the other customer classes, and described proposed housekeeping revisions tolanguage contained in Schedules 33, 40 and 210. In his rebuttal testimony, Griffith presented theCompany’s revised rate spread and rate design based on the revised revenue increase of $80.1million (or 14.1%) including the effect of the 2010 Protocol. He also addressed [ii OCA witnessZamora’s proposal of a residential three-tier inverted energy charge rate design; [ii] AARPwitness Brockway’s proposal regarding the proposed increase to the residential customer charge;[iii] WIEC witness Baron’s recommended correction to the Company’s proposed NPC energyrates; [iv] Cimarex, KIvIIGT and QEP witness Goins’ recommendation regarding demand andenergy rate design changes for Schedules 33, 46 and 48T; and [v] Casper witnesses Hill andSpringer’s testimony regarding passing on increasing costs.

48. Stefan A. Bird, Senior Vice President, Commercial and Trading for PacifiCorpEnergy, prefiled direct and rebuttal testimony and exhibits in support of the general rateapplication. (RMP Exhibit 19.) Bird’s direct testimony addressed the prudence of constructingthe Dunlap I wind-powered generation project (Wind Project) and the Commission’s Orderissued in Docket Nos. 20000-352-ER-09 (Sub 352) and 20000-363-EP-lO (Sub 363) regardingwind project capacity factors. His direct testimony also discussed the operational responsibilityfor the interconnection facilities, interconnection of the Wind Project to the Company’stransmission system and the location of the Wind Project. Bird stated the proposed rate increaseincludes a total Company capital investment of $263.9 million in the Wind Project of whichapproximately $41 .8 million is allocated to Wyoming. The proposed rate increase also includesoperations and maintenance costs associated with the Wind Project of $2.4 million (totalCompany) for maintenance, permitting obligations, local taxes and ongoing land use payments.Bird stated the actual investment and operating costs are offset in part by renewable energycredit (REC) revenue which will be passed back to customers through the Company’s annual netpower cost filings. In his rebuttal testimony, Bird rebutted the direct testimony of WIECwitnesses Fallcenberg and Higgins related to the Company’s wind resources. Bird discussed,inter alia, the Company’s wind generation, forecasts of wind resource capacity factors used forNPC, and the proposed treatment of REC revenues.


49. Cindy A. Crane, Vice President, Jnterwest Mining Company and Fuel Resourcesfor PacifiCorp Energy, prefiled confidential and noncoiifidential versions of her direct andrebuttal testimony and exhibits. (RMP Exhibit 20.) Her direct testimony addressed theCompany’s overall approach in obtaining coal supplies for its coal-fired plants, and supportedthe level of coal costs included in fuel expense in this rate filing. Crane [i] explained the primaryreasons for the coal cost increases included in this general rate case; [ii] provided background onthe revisions to third-party contracts which drive the majority of the increase in coal costs; [iii]reviewed the Company’s affiliate mine coal costs and compared them to supply alternates; and[iv] demonstrated the benefits to Wyoming customers from the Company’s coal supply strategy.Crane stated that, while coal costs have increased significantly (approximately $78 millionCompany-wide since the 2009 general rate case), the Company’s diversified coal strategy, andits reliance on fixed-price contracts, indexed contracts and affiliate-owned coal mines to meet thefuel needs of its coal fired power plants have resulted in a long-term, stable, low-cost supply ofcoal for its customers. In her rebuttal testimony, Crane responded to [i] OCA witness Parrish’sproposed disallowance of the Company’s fuel stock costs; [ii] WIEC witness Falkenberg’stestimony regarding fuel quality problems at the Bridger plant; and [iii] conceptually acceptedWIEC witness Widmer’s adjustment regarding removal of the effects of the Bridger CoalCompany fines and citations, as corrected by the Company.

50. Gregory N. Duvall, PacifiCorp’s Director of Long-Range Planning and Net PowerCosts, prefiled direct and confidential and nonconildential versions of rebuttal testimony andexhibits in support of the Company’s application. (RMP Exhibit 21.) In his direct testimony,Duvall presented the Company’s proposed net power costs (NPCs) for the 12-month test periodending December 31, 2011. Duvall [i] addressed the specific issues related to the GRID modeldescribed in the Commission’s Order in Subs 352 and 363; [ii] described the major cost driversin the 2011 NPCs; and [iii] presented the Company’s updated wind integration charges andexplained how they were incorporated into this case. Duvall also addressed certain issues raisedby WIEC witnesses in the 2009 general rate case filing. He stated the total Company NPCs forthe test period were approximately $1.377 biffion, with Wyoming’s allocated share being $241.4million, as compared to net power costs of approximately $ 1.003 billion on a company-wide inthe 2009 general rate case. In his rebuttal testimony, Duvall responded to the proposedadjustments to the Company’s NPCs presented by OCA witness Parrish and WIEC witnessesFalkenberg and Widmer in their direct testimony. On rebuttal, he presented and discussed theCompany’s recommendation for total company-wide NPCs of $1.35 1 billion, or $235.6 millionon a Wyoming-allocated basis.

WIEC Prefiled Direct and Rebuttal Testimony

51. David E. Peterson, Senior Consultant for Chesapeake Regulatory Consultants,Inc., prefiled direct testimony and exhibits on behalf of WIEC. (WIEC Exhibit 100.) Heanalyzed the proposed rate increase and presented the results and recommendations of hisanalysis. Peterson advocated the use of an historical test year period for setting rates, arguingthat the use of a forecasted test year is unwarranted, and explained the basis for his position thatan actual test period was preferable to a forecasted test period. He also stated his revenuerequirement analysis utilized an end-of-year rate base instead of an average rate base. Peterson’srevenue requirement study was based on an actual test year for the twelve month period ending


June 30, 2010, adjusted for lcnown and measurable changes through June 30, 2011. Petersonalso described his adjustments to the Company’s revenue requirement analysis. Based on hisanalysis, Peterson recommended current revenues be reduced by $547,303 to produce the 7.82%overall rate of return for Rocky Mountain Power recommended by WIEC witness Gorman.

52. Kevin C. Higgins, a Principal in the firm of Energy Strategies, LLC, prefileddirect and cross-answer testimony and exhibits on behalf of WIEC. (WIEC Exhibits 101 and102, respectively.) Higgins’ direct testimony addressed [i] the appropriate revenue requirementassociated with the forecasted test period ending December 31, 2011, proposed by the Company,[ii] long term cost considerations, and [iii] implementation of demand response programs inWyoming. Higgins recommended replacing the Company’s use of the 2010 Protocolmethodology with the MSP Revised Protocol plus a 0.7% adder. He also made a separatecalculation at the end of his revenue requirement analysis to reflect applying the rate impact capincluded in the Stipulation approved by the Commission in Docket No. 20000-381-EA-10 (Sub381). Higgins described his other proposed adjustments to Rocky Mountain Power’s revenuerequirement including [i] lowering the revenue requirement to reflect bonus tax depreciationresulting in a reduction in Wyoming revenue requirement of $6,131,568; [ii] a reduction of$16,946,097 to the Wyoming revenue requirement to reflect REC sales, inclusive of carryingcharges; [iii] a reduction of $45,655 in revenue requirement to reflect SO2 allowance sales in2011, inclusive of carrying charges; [iv] a wage and benefit expense of $497,834,458 reflecting areduction to the Wyoming revenue requirement by $2,280,613; [v] an adjustment to non-laborO&M expenses resulting in a reduction in Wyoming revenue requirement of $1,664,560; [vi]denying the cost recovery for Medicare tax deferrals resulting in a reduction of $565,226; [vii]denying the Company’s adjustment to depreciation rates for the Klamath Hydro Project resultingin a reduction in the revenue requirement of $1,134,518; and, [viii] approving other adjustmentsproposed by WIEC witnesses. Higgins’ revenue requirement analysis produced a reduction inthe Company’s initial revenue requirement request by $68,682,136, comprised of a reduction inthe non-power cost revenue requirement of $46,487,560, and a reduction of $19,762,972 to thenet power revenue requirement. WIEC’s revenue requirement, as adjusted for a correction tostate income tax (Wyoming has no state income tax), results in a proposed revenue requirementincrease of $29,222,966 as compared to the Company’s initial request of $97,905,102. (WIECExhibit 101, p. 9.) Higgins also recommended the Commission open a docket on the planning,evaluation and cost effectiveness of the Company’s future environmental upgrades.

53. In his cross-answer testimony, Higgins discussed the relationship between therevenue requirement adjustments proposed by OCA witness Parrish and those he proposed forthe test year ending December 2011, in order to clarify which of OCA’s non-NPC adjustmentsmight conceptually be added to WIEC’s proposed revenue requirement adjustments and thosethat should not be added because they were duplicative. His cross-answer testimony alsoaddressed the testimony of PRBRC witnesses Fisher and Steinhurst and Cimarex, KMJGT andQEP witness Goins concerning recovery of the Company’s major environmental upgrade costs.Further, Higgins updated his revenue requirement calculation to reflect certain new informationprovided by the Company, including an adjustment to reflect the effect of bonus tax depreciationbased on information provided by the Company on May 2, 2011.


54. Michael Gorman, Consultant with the firm of Brubaker & Associates, Inc.,prefiled direct testimony and exhibits on behalf of WIEC (WIEC Exhibit 103), offering hisrecommendations for a fair Company capital structure, return on common equity and overall rateof return. Gorman proposed adjustments to the Company’s proposed capital structure which hedeemed to be too heavily weighted with common equity. He recommended a capital structurecontaining what he found to be a reasonable mix of debt and equity, stating this would minimizethe Company’s cost of capital, while allowing it to maintain its bond rating and financialintegrity. He recommended a ROE of 9.75%, based upon his use of three Discounted Cash Flow(DCF) models, a RiskPremium Study and a Capital Asset Pricing Model (CAPM) analysis, andan overall rate of return (ROR) of 7.82% based on his proposed capital structure. He stated thathis recommended ROE and proposed capital structure would give Rocky Mountain Power anopportunity to realize cash flow financial coverage and balance sheet strength that conservativelysupport the Company’s current bond rating. He stated that his recommended ROE {i] representsfair compensation for the Company’s investment risk, and [ii] will preserve the Company’sfinancial integrity and credit standing. He also critiqued Company witness Hadaway’s proposedROE of 10.6% and explained why he believed it was excessive.

55. Dennis E. Peseau, President of Utility Resources, Inc., prefiled direct testimonyand exhibits on behalf of WIEC, addressing Rocky Mountain Power’s investment in the Populusto Terminal transmission line (in Segment B of the Gateway Project) and the extent to which itshould be included in the Company’s rate base. (WIEC Exhibit 104.) Peseau recommended thatthe Commission disallow 50% of the Company’s investment in the Populus to Terminaltransmission line as not being used and useful at the present time. His recommendation wasbased on the idea that the transmission line will only be able to operate at 50% capacity for atleast six years and possibly indefinitely and therefore was not totally used and useful for thebenefit of customers. Peseau stated that, if the Commission were to adopt a forecast test period,his recommendation would reduce rate base by approximately $400 million (total Company)which would lower its Wyoming revenue requirement by approximately $6.2 million ascalculated by WIEC witness Higgins. He stated that, if the Commission were to adopt anhistorical test period, his recommendation would reduce rate base by approximately $115 million(total Company) and, therefore lower its Wyoming revenue requirement by approximately $1.6million as calculated by WIEC witness Peterson.

56. Mark T. Wicimer, Utility Regulatory Consultant and Principal of NorthwestEnergy Consulting, LLC, prefiled confidential and noncorifidential versions of direct testimonyand exhibits addressing PacifiCorp’s Generation and Regulation Initiatives Decision (GRID)model and the normalized NPC GRID produced for the forecasted test period ending December31, 2011. (WIEC Exhibits 105 and 106.) In his testimony, he presented eleven Wyomingadjustments, which total approximately $3.0 million. Widmer stated his adjustments were madeto reflect reasonable results of operation of PacifiCorp’s system, to match costs with benefits, toexclude costs which should not be recoverable, and to make corrections.

57. Randall J. Falkenberg, Utility Regulatory Consultant and President of RFIConsulting, Inc., prefiled confidential and nonconfidential versions of his direct testimony andexhibits on behalf of WIEC, addressing the GRID model study of NPCs for the forecast testperiod ending December 31, 2011, and issues concerning new renewable energy resources

18 Docket No. 20000-384-ER-l 0

included in the test year. (WIEC Exhibits 107 and 108.) Falkenberg stated WIEC recommendedNPCs of $1,302 million (total Company) in contrast to the Company’s requested NPCs of $1,376million (total Company) resulting in a reduction to the Wyoming allocated revenue requirementof $12.0 million. Falkenberg and WIEC witness Widmer identified and discussed more than 35adjustments to Rocky Mountain Power’s test year NPC GRID study. Falkenberg also expressedhis concerns with the Company’s more recently constructed wind projects and their energyproduction, which he has calculated for the 2009-2010 period to be 22% below forecasted levels.He asserted that the Company’s forecasts of wind generation have been overstated. Finally,Falkenberg recommended the Commission not grant any new Certificates of Public Convenienceand Necessity for PacifiCorp-owned projects until it has explained why its forecasts have beeninaccurate and the new project developments are adequately supported.

58. Stephen J. Baron, President and a Principal of Kennedy and Associates, prefileddirect, cross-answer and supplemental testimony and exhibits on behalf of WIEC. (WIECExhibits 109, 110 and 111.) Baron’s direct testimony responded to Rocky Mountain Powerwitnesses Paice and Griffith regarding retail class cost of service study (COSS) issues, the spreadof the revenue increase to the various rate schedules and rate design. Regarding the Company’sCOSS presented by Paice, Baron recommended changes to the Company’s allocation methodconsistent with the Revised Protocol methodology. His recommendations for the Company’sallocation methodology included the separation of the thermal portion of energy-related NPCsinto Heavy Load Hour (HLH) and Light Load Hour (LLH) costs and allocation of these costsbased on HLH and LLH energy use by rate class on a monthly basis. He also recommended thatthe 25% portion of demand-related production and transmission costs classified as “energyrelated” be allocated to rate classes using this same HLHILLH basis. The impact of this revisedanalysis would reduce the cost responsibility of Rate Schedule 48T, with the cost responsibilityto Rate Schedules 46 and Schedule 2 (Residential) staying approximately the same as proposedby the Company. (WIEC Exhibit 109, p. 17.) Baron also offered his own COSS incorporatingan alternative allocation of demand-related production costs using a 5 CP method and a revisedallocation of transmission costs that reflect the PacifiCorp Open Access Transmission Tariff costallocation. Baron stated that he does not recommend that his alternative COSS be adopted at thistime because of issues of gradualism but believes it should be considered as a possiblealternative methodology in future Rocky Mountain Power rate cases. Regarding rate spread,Baron presented the results of his alternative COSS that reflects the classifying of energy-relatedcosts on an HLHJLLH basis. (See, WIEC Exhibit 109, p. 24.) Regarding rate design, he offereda correction to a discrepancy between the proposed NPC energy and demand charges for Rates46, 48T and 33. In his cross-answer testimony (WIEC Exhibit 110), Baron responded to thedirect testimony of OCA witnesses Backofen and Zamora on class cost of service and rate spreadissues. He characterized Backofen’s proposal to totally redo the Company’s COSS asconstituting a radical departure from previous Commission-approved methodologies and adeparture from reasonable and well-established cost causation principles. Similarly, Baronrecommended rejection of OCA witness Zamora’s rate spread proposal as it is based onBackofen’s flawed COSS analysis. In his supplemental testimony (WIEC Exhibit 111), Baronupdated the two COSS studies that he presented in his direct and cross-answer testimony toreflect the updated roughly $80 million revenue increase presented by the Company in rebuttal.He also presented corresponding rate spread analyses based upon his updated COSS.


OCA Prefiled Direct and Cross Answer Testimony

59. Bryce J. Freeman, OCA Aclmirñstrator, prefiled confidential and nonconfidentialversions of his direct and supplemental testimony and exhibits (OCA Exhibits 201 and 202),addressing [i] the cost of capital; [ii] the prudence of the Company’s pollution controlinvestments; [iii] the prudence of the Company’s investment in the Populus to Ben Lomondtransmission upgrades and the residual costs of the Ben Lomond to Terminal upgrade; [iv]transmission and distribution investments and related quality of service; and [v] the Company’sDSM programs. Freeman recommended a ROE of 9.5%; a cost of preferred stock of 5.43%; acost of long term debt of 5.82% and a weighted average cost of capital of 7.77%, based on hisuse of the Company’s estimated capital structure at December 31, 2010, consisting of 46.6%debt, 0.3% preferred stock and 53.1% common equity. Freeman supported including theCompany’s pollution control investments in rate base and that the associated increase inoperating expenses be recovered from customers. Freeman recommended the Company beallowed to recover the investment in the Populus to Ben Lomond transmission line, the Borah toBen Lomond upgrade and the residual costs of the Ben Lomond to Terminal line totalingapproximately $91 million on a Wyoming-allocated basis. He further recommended therecovery of increased distribution capital and maintenance costs subject to a showing of systemimprovement, reliability and performance in the near and long term. Freeman argued that theCompany failed to comply with the Commission’s prior directive in Docket No. 20000-353-ER-09 to address the creation of a demand response market in its next rate case. He recommendedthe Commission reiterate its direction from the prior case and direct the Company to include adiscussion of DSM resources, an Energy Imbalance Market, and other markets, in a report to befiled within six months of the issuance of the final order in this case. In his supplemental directtestimony (OCA Exhibit 202), Freeman disclosed and discussed an oversight on page 56 of hisdirect testimony regarding the Wyoming Infrastructure Authority (WIA) concerning whetherpossible agreements with the Company to jointly develop any of the proposed Gateway segmentseither inside or outside Wyoming existed. Freeman clarified that, in August 2007, an interimagreement between WIA and other parties was entered into to take the initial steps in codeveloping the transmission projects and to examine the business, regulatory and technical issuesthat would govern a longer-term relationship.

60. Denise Kay Parrish, OCA Deputy Administrator, prefiled confidential andnonconfidential versions of her direct testimony addressing OCA’s concerns andrecommendations regarding the Company’s proposed revenue increase. (OCA Exhibit 204.) Inher direct testimony, Parrish recommended the Commission grant the Company an increase ofapproximately $67.8 million in Wyoming retail revenues based on her computations. (ScheduleOCADKP-2.) Parrish’s recommendation did not include $ 15-20 million in REC sales revenuesthat Parrish believed should flow back to ratepayers either in this case or in a later energy costadjustment mechanism (ECAM) filing. Parrish recommended that, should the Commissiondecide to include REC revenues in the Company’s revenue calculations, an increase ofapproximately $50 million would be appropriate. She stated the Company did not include RECrevenues in this case as an offset to the revenue increase because the Commission determined inthe last rate case that the REC revenues be flowed back to customers through the ECAM process.Parrish stated OCA, consistent with the Commission’s directive, removed the REC revenuesfrom this case and anticipates including them as an offset to net power costs in the next ECAM

20 Docket No. 20000-384-ER-i 0

filing. Parrish stated her revenue requirement recommendation was derived from a series ofadjustments to the costs and investments used to determine the overall increase in revenues thatshould be incorporated into retail rates. (See, Schedule OCA_DKP-3; Table in OCA Exhibit204, p. 13.) Parrish recommended adjustments for bonus depreciation which reduced therequired rate increase by approximately $5.2 miffion. She stated the agreed upon cap of 0.70%of the Wyoming requirement computed using the Revised Protocol approved in Docket No.20000-38 1-BA-b (Sub 381) should be applied in this case. The interjurisdictional allocationsdriven rate mitigation cap further reduced OCA’s recommended revenue by approximately $5.2million. Parrish also recommended, inter alia, [i] modif’ing the level of uncollectible revenuethat is permitted to be included as an expense in determining the revenue requirement, resultingin a reduction of approximately $160,000; [ii] an $80,000 adjustment to correct errors in theCompany’s application; [iii] an adjustment of approximately $26,000 to operations andmaintenance expenses; [iv] a reduction of approximately $800,000 to incentive payments andemployee bonuses; and [v] reducing the required increase in wage expense by approximately$360,000.

61. Charles W. Backofen, Senior Consultant with the firm of D’Onofrio &Associates, LLC, prefiled direct testimony and exhibits on behalf of OCA, to provideindependent analyses of the cost allocation methodologies used in Rocky Mountain Power’sclass cost of service study (COSS) and offer his recommendations. (OCA Exhibit 206.)Backofen recommended that the Commission order [i] the use of an allocation methodology forproduction plant that first makes functional classifications of production plant, i.e., base,intermediate and peak resources, thereafter applying the appropriate 12 Monthly Coincident Peak(12 CP) and Average and 12 CP allocation factors; [ii] that the COSS not treat any productionplant as seasonal; [iii] order environmental production plant and related expenses to be allocatedon an energy basis; [iv] an allocation methodology for Transmission Plant that first recognizedthe two sub-functions of Transmission Plant, bulk transmission and sub-transmission, thereafterapplying an allocation that reflects a 12 CP demand for bulk transmission and a class non-coincident peak (NCP) demand for sub-transmission; [v] that the hybrid allocation factor used toallocate distribution substations and primary lines incorporate class NCP demand that recognizedthe diversity within and between customer classes; and [vi] that, for all demand and energyrevenue accounts, the 12 CP demand allocation F12 be used to allocate the demand portion. Theresults of Backofen’s recommended COSS adjustments on the various customer rate classes areset forth in OCA Exhibit 206, Schedule CWB-20.

62. Amy J. Zamora, Senior Rate Analyst for the OCA, prefiled direct, revised direct,and cross-answer testimony and exhibits presenting the OCA’s position regarding RockyMountain Power’s rate design, line extension policy and tariff changes. (OCA Exhibits 207,208, and 209.) Zamora proposed changes to the rate design for the Schedule 2, (residential)customers, recommending a three-block inverted volumetric rate structure instead of the currenttwo-block inverted structure. She stated the three-block inverted structure would be moreappropriate for low-use, average-use and high-use customers, as it promotes energy efficiencyand addresses the differences these customer groups have regarding usage, cost causation andsystem impacts. Based on this revised rate structure, Zamora recommended a rate design thatimposes only a single monthly customer charge of $20.00 for all residential customers based onthe results of the class cost of service study. Zamora proposed an increase to the residential class

21 Docket No. 20000-384-ER-b

of 12% compared to the Company’s proposed increase of 21.54%. OCA took no issue with theCompany’s proposed rate designs for the remaining customer classes. Regarding the Company’sline extension allowances, Zamora stated the OCA believed the allowances should be updated toreflect the current COSS-based costs. On the strength of OCA’s COSS, she recommended thatthe allowance for residential customers be set at $1,340 and that the non-residential allowancefor all other customers be set at 0.90 times their annual revenue paid to the Company. Shouldthe Commission not accept the OCA’s cost of service, she recommended the line extensionallowances be set according to the cost of service that the Commission does accept. Zamorastated the OCA believed the Company’s proposed changes to the line extension policy languagein Rule 12 were reasonable; and the OCA did not have any issues with [i] the Company’sproposal to revise the curtailment payment in Schedule 73 by using the same methodology usedin previous cases, and [ii] its proposed housekeeping changes to Schedules 33, 40 and 210.

63. Tn her revised direct testimony (OCA Exhibit 208), Zamora discussed formulacorrections to the exhibits filed with her prefiled direct testimony regarding rate design. Herrevised direct testimony also incorporated small changes from OCA witness Backofen in the costof service study model that were discovered in response to WIEC Data Request 2.1. Zamora’scorrections had a minimal impact on the monthly billings for the various customer classes.

64. In her cross-answer testimony (OCA Exhibit 209), Zamora addressed thetestimony of Granite Peak witness Trembath, AARP witness Brockway, and WIEC witnessBaron. Regarding Granite Peak witness Trembath’s recommendations that the Company adopt amore balanced and forward thinking approach in applying its line extension policy and that theline extension allowance should be increased four-fold, Zamora stated Trembath’srecommendations would unfairly allocate additional costs to other rate payers in order to furthereconomic development that may attract future customers. She deemed his recommendations notto be in the public interest. Regarding Brockway’s testimony that increasing the customercharge will increase the burden on low-use customers, specifically customers that are 65 andover, Zamora stated, inter alia, that Brockway’s testimony only takes into account the low-usecustomer with a focus on senior citizens and her arguments are based on information that iseither not correct or not completely relevant. Zamora argued that rates must be cost-based toeliminate inter-class and intra-class subsidies; they must be fair for all of the utility’s customersand not just one customer class. Zamora agreed that increasing the customer charge willadversely affect low-use customers but argued that the customer charge should recover a sizeableportion of the fixed costs each customer imposes on the system. She stated that, if the monthlycharge does not completely recover the fixed cost, the remaining amount will be recovered involumetric rates. Regarding WIEC witness Baron’s identification of an error in the Company’snet power cost calculation for Rates 45, 48T and Rate 33, Zamora stated she verified with RockyMountain Power that an error existed. Because of this error, Zamora ran her rate design modelusing the corrected inputs. She included new spreadsheets demonstrating the changes resultingfrom correction of the NPC input.

AARP Prefiled Direct Testimony

65. Nancy Brockway, proprietor of NBrockway & Associates, prefiled directtestimony and exhibits on behalf of AARP. (AARP Exhibit 500-507.) Her direct testimony

22 Docket No. 20000-384-ER-b

discussed [ii the proposed increase in the customer charge from $20 to $24 a month; [ii] theCompany’s proposed ROE; [iii] executive bonuses; and [iv] service reliability. Sherecommended the Commission maintain the current monthly customer charge at $20 and rejectthe Company’s proposal to raise the residential customer charge, stating the Company’sproposed increase to $24 per month would adversely impact low-use residential customers andwould not benefit low-income or elderly customers. She stated that increasing the customercharge would lessen the customer’s incentive for energy efficiency since reducing usage wouldnot enable customers to avoid the higher customer charge. She stated the Company has notaltered its efforts regarding demand side management due to its implementation of highercustomer charges in the past. Further, Brockway contended that increasing the revenue collectedthrough the customer charge reduces the Company’s risk which should therefore be reflected inthe Company’s ROE. Regarding the Company’s proposal for its Supplemental ExecutiveRetirement Plan (SERP), Brockway stated that SERP benefits are not reasonable andrecommended SERP costs be removed from test year expenses as they exceed payments neededto fund normal retirement benefits. She recommended no specific level of ROE butrecommended the Commission consider, when it determines an appropriate ROE: [ij risk; [ii]economics factors, such as incomes and opportunities in an area; and [iii] service quality.Regarding service quality, Brockway stated that customers have complained for years of thenumerous outages in the Company’s service territory but the outage problems persist. Accordingto Brockway, substandard service quality should be a factor in determining ROE as a matter ofjustness and fairness.

Cimarex Energy Co., KI’IIGT and QEP Preffled Direct Testimony

66. Dennis W. Goins of Potomac Management Group, prefiled direct and cross-answer testimony and exhibits on behalf of Cimarex, KMIGT and QEP. (Cimarex Joint Exhibits700 and 704.) Goins provided his review of the Company’s environmental retrofits to certaincoal plants and discussed the Company’s proposed Schedules 46 and 48T. Based on his reviewand evaluation, he concluded: [i] the environmental retrofit program costs for Bridger 1 and 3,Dave Johnston 3, Hunter 2, Huntington 1, Naughton 2 and Wyodak 1 coal-fired generation unitswere included in the Company’s proposed $97.9 million rate increase; [ii] the Company hadneither identified nor separated pollution control costs incurred to meet existing or anticipatedenvironmental regulations; [iii] PacifiCorp has begun to evaluate early retirements of its coal-fired generating units, including those at which pollution control costs are at issue in this case;and [iv] the proposed rate designs for Schedules 46 and 48T could be modified to promote moreefficient electricity use by these Large General Service customers. Goins recommended: [i]allowing recovery of prudently incurred pollution control costs, with prudence being determinedby separately reviewing the costs incurred in complying with existing regulations and thoseincurred in complying with anticipated regulations; [ii] the Commission order the Company todemonstration the prudence of continuing to invest in pollution control retrofits and upgrades onits coal-fired generating units, especially those the Company is considering for early retirementor fuel switching; and [iii] the Commission reject Rocky Mountain Power’s proposed rate designfor Schedules 46 and 48T and approve his proposed rate design for the Schedules. In suggestingmodifications to the Company’s proposed Schedule 46 and 48T, Goins stated his objectives wereto encourage usage efficiency by improving load factors. He stated that, in developing hisrecommended rate Schedules 46 and 48T, he accepted the Company’s overall revenue target for

23 Docket No. 20000-384-ER-b

each rate, left the net power cost component unchanged, and focused on changes in the basedemand and energy charges that encourage load factor improvements while not significantlychanging the relative rate increases for customers served at different voltages. Goins did notrecommend changes to the Company’s target revenue requirement for Schedules 46 or 48T.Goins stated his recommended changes have only intraclass effects and offered his CimarexExhibit 702 which illustrated the revenues by rate component for Rate Schedules 46 and 48Tunder his proposal.

67. Tn his cross-answer testimony, Goins responded to OCA witness Backofen’srecommendations and proposals regarding cost of service classification and allocation issues.Goins concluded that OCA’s allocation of fixed production costs utilizes an arcane methodologythat is not used by any regulatory commission. Goins stated OCA’s Base, Intermediate orPeaking category (BIP Method) for allocating demand-related production costs is flawed becauseit does not accurately reflect class cost responsibility. He further concluded that OCA’sproposed methodology unfairly shifts costs to Wyoming industrial customers served underSchedules 33, 46 and 48T. Based on his conclusions, Goins recommended [iJ the Commissionreject OCA’s proposed BIP method for allocating demand-related production costs and approvethe Company’s proposed 12CP Method (adjusted to reflect modifications recommended byWIEC witness Baron) and the 12CP-based rate spread proposed by Baron; and [ii] theCommission reject OCA’s proposal to classify all fixed costs of environmental retrofitinvestments as energy-related costs, and approve Rocky Mountain Power’s proposed 75%demandl25% energy classification scheme.

PRBRC Prefiled Direct Testimony

68. Jeremy Fisher Ph.D., a scientist with Synapse Energy Economics, prefiled directtestimony and exhibits on behalf of PRBRC. (PRBRC Exhibit 1000.) Fisher addressed thecurrent and possible future federal environmental regulations likely to impact the operations andeconomics of Rocky Mountain Power’s coal plants. He also discussed [i] the Company’streatment of these regulations in both the last relevant Integrated Resource Plan (IRP) and thecurrent general rate case, and [ii] the Company’s stated expectations for these regulations andhow they will impact Rocky Mountain Power’s coal plants. Fisher identified the numerouspublicly available documents he reviewed as part of his analysis, and stated that he had focusedon the Company’s Dave Johnson 3 and 4, Jim Bridger 1-4, Naughton 1-3, Wyodak 1, Hunter 1and 2, and Huntington 1 and 2 coal units.

69. Based on his review, Fisher concluded that PacifiCorp had not addressed andaccounted for all current and reasonably expected environmental costs in its planning process.He stated that PacifiCorp’s planning for current and possible environmental compliance costshad been limited, he found no evidence that the Company had adequately planned forcompliance costs associated with either the upcoming federal regulations or the expectedstrengthening of existing regulations. He recommended the Commission require the Company toprovide a full analysis and accounting of the impact of retrofits on coal plants to determine if theCompany’s actions are consistent with least-cost principles. Fisher estimated that 24% of theCompany’s proposed rate base increase is due to new retrofits to meet existing environmentalregulations at old coal plants. Fisher concluded that Rocky Mountain Power has: [ij failed to

24 Docket No. 20000-384-ER-b

account for Company Projected Retrofits in forward-planning; [ii] failed to inform theCommission of expected additional compliance costs facing its coal plants beyond the CurrentCase retrofit; [iii] failed to account for Emerging Retrofits in any meaningful way; [iv] failed topresent any of these additional expected costs to the Commission as part of this rate case; and [v]failed to show that the Current Case Retrofits are in keeping with least cost principles.Regarding environmental compliance costs likely to be faced by PacifiCorp’s coal plants andhow it has treated them in its IRP and general rate case, Fisher stated, in his opinion, noreasonable decision can be made on the future viability of these plants without explicitlyaddressing each of the current and possible future regulations.

70. William Steinhurst, Ph.D., Senior Consultant with Synapse Energy Economics,prefiled direct testimony and exhibits on behalf of PRBRC, discussing the prudency of theenvironmental upgrade investments made by the Company and addressing the coordinationbetween the Company’s IRP activities and its proposed rate case requests. (PRBRC Exhibit1001.) Steinhurst summarized his conclusions, stating, inter alia, [i] Rocky Mountain Power isseeking recovery of capital and operating costs of major environmental upgrades (Current CaseRetrofits) at certain power plants; [ii] over the near- to mid-term, the Company will likely incursubstantial additional costs to keep those power plants in operation due to known and likelyenvironmental regulations; and [iii] the Company was imprudent in failing to determine whetherCurrent Case Retrofits will be cost effective in light of those known and likely environmentalregulations. Steinhurst recommended: [i] the Commission disallow the costs of the CompanyCurrent Case Retrofit investments (including associated O&M costs and costs incurred due tolost output from the affected plants) until the Company shows that the costs are prudent and inkeeping with least cost principles; and [ii] the Commission require the Company to provide a fullanalysis and accounting of the impact of existing and upcoming environmental regulationsaffecting its coal plants and the full range of options for addressing those regulations, includingboth supply-side and demand-side resources. Steinhurst discussed why he believed the 24% ofthe requested rate increase attributable to the new retrofits to coal plants to meet environmentalregulations, and their associated O&M costs and costs due to lost output from the affected plants,was imprudent. (PRBRC Exhibit 1001, pp. 5-10.) He further stated the Company did notprovide sufficient evidence to support the prudency of its investments. Finally, Steinhurstrecommended the Commission take a more proactive approach by establishing a comprehensiveand consistent process to consider utility proposals for major investments in existing generatingplants.

The Union’s Prefiled Direct Testimony

71. Harold Giberson, President of the Union, filed rebuttal testimony to: [i] supportthe UWUA labor costs included in the Company’s proposed rate increase, [ii] address how theknown UWUA labor costs compare with WIEC witness Higgins’ proposal, and [iii] describe thenegotiations between UWUA and Rocky Mountain Power in arriving at the current laborcontract. (UWLJA Exhibit 800.) Giberson stated that the Union’s contract provides for a 1.5%increase in wages in October 2010, and a 1.5% increase in 2011, while Higgins recommended a0.75% increase. He further stated there are significant increases in medical benefit costs andother labor-related costs that are substantially greater than what Higgins proposed be allowed for

25 Docket No. 20000-384-ER-b

recovery in rates. He recommended the Commission reject Higgins’ proposal and approve thecost recovery of the wage and benefit costs included in Rocky Mountain Power’s case.

Governmental Intervenor Prefiled Direct Testimony

72. Peter Myers, Assistant to the City Manager of Casper, prefiled direct testimonyand exhibits on behalf of the City of Casper. (Casper Exhibit 341.) Myers stated the City hasundertaken generator studies for the waste water treatment plant and water treatment plant toensure electric reliability and provide energy efficiency. In 2010, the City received a LocalEnergy Assurance Planning Grant from USDOE as part of a nationwide effort to protect citiesfrom loss of energy. Meyers stated an energy assurance plan task force is currently working onrecommendations for placing generators at various city facilities, the recommendations areexpected to be implemented in the coming years. He identified certain measures undertaken bythe City to encourage energy efficiency and discussed the City buildings that have been affectedby outages. Myers stated that the total number of customer minutes lost due to power outageswas increasing. He concluded that customers are impacted by these outages and the averageCasper customer is experiencing increased total amounts of time without power, with or without“major events” being taken into account. He also concluded that loss of supply outages areincreasing significantly from year to year. Myers stated the City is trying to increase reliabilityto City facilities by adding generators to serve the more critical facilities, with facilities involvedwith public safety, health and welfare receiving priority. He stated the purchase and installationof generators at these critical facilities has cost the City additional monies to ensure that that therequirements of public safety, health and welfare are met.

73. David Hill, Casper’s Public Utilities Manager, prefiled direct testimony andexhibits discussing the operation, maintenance and backup generator systems for the City’s waterand sewer system. (Casper Exhibit 302.) Hill explained that the City does not own or operate itsown water plant facility but is a wholesale customer of the Central Wyoming Regional WaterSystem Joint Power Board (Joint Powers Board). Casper acts as the operating agent for thewater treatment plant and owns and operates the Sam H. Hobbs Wastewater Treatment Plant.Both the Wastewater Treatment Plant and the Joint Powers Board Water Treatment Plant useelectricity supplied by Rocky Mountain Power. Both are considered critical infrastructure for thehealth, safety and welfare of the public served by them. Hill stated the City has initiated studiesof backup generator systems for electrical power for the Wastewater Treatment Plant and theJoint Powers Board Water Treatment Plant because of the increasing number of electric outagessince 2000 at the water treatment plant. An initial study was completed in 2008 andsupplemented in 2009. (Casper Exhibit 309.) The study recommended, inter alia, emergencyelectrical generation for the Joint Powers Board Water Treatment Plant at an approximate cost of$1.76 million and for the Wastewater Treatment Plant at a cost of approximately $1.6 million, allof which will be passed on to customers.

74. Jesse Springer, an Administrative Analyst for the City, prefiled direct testimonyand exhibits analyzing the electricity cost, electric usage and peak electricity usage for City-owned operations and buildings. (Casper Exhibit 343.) Springer stated the City’s expendituressince 2006 have increased 29.63% for metered usage while actual usage has decreased by 5.34%.On average, the City is paying 3 6.95% more per kWh used. Springer stated he believed actual

26 Docket No. 20000-384-ER-b

usage decreased because of the City’s conservation efforts, capital improvements andrenovations of City buildings and operations, and the City’s upgrade to energy efficient lights in50% of its traffic lights. He discussed, inter alia, the amount of money the City spent on energyefficiency and general improvements, the amount ofKW used, and the price per kWh paid by theCity.

75. Eric Gromko, Electrical Engineer, prefiled direct testimony and exhibits on behalfof the Governmental Intervenors. (Casper Exhibit 344.) Gromko stated he reviewed the RockyMountain Power Powder River Area Transmission System Five-Year Study, 20 10-2015 (thePowder River study), a study produced by the Company that provides a five-year estimate andanalysis of its current 230 kV to 115 kV to 69 kV distribution systems. (Casper Exhibit 319.)Gromko described the Rocky Mountain Power electrical system serving the City of Casper anddiscussed the electrical capacity for the City, the growth of electrical systems in each of theGovernmental Intervenors’ respective service areas, and the size of transmission line andfacilities needed to serve the City. He identified what he found to be inadequacies and problemswith the Rocky Mountain Power electrical system serving the Casper area, including the lack ofsystem redundancy. He also discussed, inter alia, the cause of the reliability issues experiencedin the Governmental Intervenors’ service areas and what is needed to resolve them. Gromko’sgeneral conclusion, based upon the various studies he referenced in his testimony, was that,although the Company provides power to its customers, the power is not necessarily reliable orprovided in a safe manner. (Casper Exhibit 344, p. 62.)

76. Wallace Trembath Jr., Vice President of Turnkey Services, Inc., prefiledtestimony and exhibits on behalf of the Governmental and Intervenors (Casper Exhibit 345.) Hediscussed his review of Rocky Mountain Power’s study called “Casper 12.5kV Urban SystemDistribution Study for the years 2010-2015” dated November 20, 2009, which describes theCompany’s transmission system. (Casper Exhibit 321.) Trembath also discussed the PowderRiver study, dated November 9, 2010, which focuses on the 230kV, 69kV and 57kVtransmission systems, including the transmission and distribution substations in the PowderRiver area. (Casper Exhibit 319.) This study identified transmission and distribution systemconstraints and local reinforcements needed to meet area load growth from the summer of 2010to the winter of 2014-2015. Trembath identified deficiencies and problems in the Company’selectric transmission and distribution system and identified the upgrades he believed wouldimprove the reliability and dependability of the systems. He also identified what he believed tobe the cause of the reliability issues experienced in the Governmental Tntervenors’ service areasand the repairs and upgrades that would be necessary to improve the system reliability.Trembath commented on the utility facilities available in the Casper Airport area where GranitePeak was planning on developing the Bishop Industrial Rail Park, and on the discussionsbetween the Company and Granite Peak regarding the construction of additional utility facilitiesto serve the area and the associated cost responsibilities. Trembath expressed his belief that theline extension policy being applied to the Bishop Industrial Rail Park (the Rail Park) wasstrangling development at that location. Generally, Trembath concluded, based on his expertiseand analysis of the Company-provided information, that the Company was not currentlyproviding available and reliable power to Natrona County citizens. (Casper Exhibit 345, p. 114.)

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Granite Peak Prefiled Direct Testimony

77. Trembath also prefiled testimony and exhibits on behalf of Granite Peak (GranitePeak Exhibit 400.) Trembath’s direct testimony addressed Granite Peak’s efforts to obtainelectric capacity and service to its Rail Park, a development outside of the City of Casper ownedby Granite Peak that is intended to provide rail access to businesses within the Rail Park.Trembath stated that, in order to get electricity to the Rail Park, Granite Peak signed anEngineering Service Agreement (ESA) with Rocky Mountain Power under which Granite Peakpaid the Company $10,000. As required under the ESA, Rocky Mountain Power provided twoInterconnect/System Impact Study Reports, dated July 7, 2010, and September 1, 2010, (SystemImpact Studies) which determined that significant upgrades to the Company’s system werenecessary in order to provide the Rail Park with more than 2.5 MW of capacity, and it informedGranite Peak that the existing distribution system does not have the capacity to serve loads at theRail Park in excess of 2.5 MW. Trembath discussed what system upgrades were needed to servethe Rail Park, the cost of those upgrades and the length of time it would take to complete them.He stated that Rocky Mountain Power has a fundamental obligation to provide timely, adequate,reliable power to all potential customers, including industrial customers such as those that willlocate in the Rail Park. Trembath recommended the Company adopt a more balanced approachto future load requests and capacity needs and that the Company should avoid placingextraordinary infrastructure upgrade costs on existing or potential customers who requestincreased capacity or line extensions. He also recommended the Commission consider whetherRocky Mountain Power has chosen to forego needed investment in distribution facilities servingcommunities such as Casper, in favor of other facilities that may have been overbuilt or may notyet be needed. If this were the case, he suggested the Commission deny the Company recoveryof these investments, and instead order Rocky Mountain Power to invest in Wyomingcommunities where additional capacity is needed. He further recommended the Company adopta more forward-thinking approach to growth in Casper. Regarding line extensions, Trembathrecommended the Commission order Rocky Mountain Power to facilitate a collaborativeregarding line extension issues. Trembath provided observations and five recommendations forRocky Mountain Power’s line extension policy. (Granite Peak Exhibit 400, pp. 10-12.) Lastly,he recommended the Commission order Rocky Mountain Power to facilitate a collaborative withGranite Peak, the Governmental Intervenors, other developers and customers, between this andthe next rate case in order to develop mutually beneficial solutions to the lack of adequate andreliable electrical power in the Casper area and to draft a more workable line extension policy forthe Company, all of which would be submitted in a report to the Commission. Trembath statedthat members of the Commission’s engineering staff would be welcome at meetings of thecollaborative.

USDOE Cross-Answer Testimony

78. Dwight D. Etheridge, Principal and Vice President of Exeter Associates, Inc.,prefiled cross-answer testimony on behalf of the USDOE, (USDOE Exhibit 601) in which headdressed the impact of Rocky Mountain Power’s proposed rate increase on USDOE’s RockyMountain Oil Testing Center (RMOTC), to ensure that USDOE’s facilities were being equitablytreated with regard to cost allocation and rate design proposals. Etheridge responded to OCA’soffering in its direct testimony of a new class COSS methodology that he believed favored someclasses over others, to the detriment of RMOTC. He also addressed OCA’s failure to consider

28 Docket No. 20000-384-ER-b

ratemaking treatment of RECs in this case. Etheridge stated the OCA’s proposed productionplant allocation proposals were not expected from an entity charged with representing allconsumer interests, including RMOTC. Etheridge stated OCA abandoned the long-standingpractice in Wyoming of classifying 75% of the Company’s production plant costs as demand-related and 25% as energy-related. He took issue with OCA witness Backofen’s proposal toclassify 53% of the Company’s production plant costs as energy-related, which [ij produces adramatic shift of costs and the allocation of revenue responsibility among the rate classes and [ii]led OCA to propose substantially higher rates than would otherwise be the case for industrialcustomers like RMOTC. Etheridge stated that Backofen’s alternate proposal compounds thenegative effects of his primary proposal and nearly triples the energy-related classification ofRocky Mountain Power’s production plant to almost 72%. Etheridge recommended theCommission reject OCA’s allocation proposal as it represents a dramatic and unreasonabledeparture from past practice. He stated it is poor ratemaking policy to undertake dramatic shiftsin inter-class revenue responsibility simultaneously with the largest Rocky Mountain Power ratecase in Wyoming history.

79. Regarding RECs, Etheridge recommended the Commission adopt WIEC witnessHiggins’ proposal, which would reduce the revenue requirement by approximately $17 million.Etheridge stated the proposed alternative REC revenue treatment jointly proposed by OCA andWIEC in Rocky Mountain Power’s ECAM case in Docket No. 20000-368-EA-10, and aspresented by Higgins in his direct testimony in this case, is consistent with past Commissionpractice. Etheridge stated Higgins’ proposal eliminates unnecessary rate volatility; affirms theCommission decision that it is the customers who should benefit from RECs and provides a fairincentive to the Company.

Summary of Evidence Supporting the Stipulation at the June 20-21, 2011 Public ContestedRate Case Hearing

80. Jeffrey K. Larsen, Rocky Mountain Power’s Vice President of Regulation,prefiled testimony and exhibits in support of the Stipulation offered by the parties to thisproceeding. (RMP Exhibit 67.) Larsen summarized this testimony, stating that the Stipulation(Joint Exhibit 1) was the result of numerous and lengthy discussions, which led to 16 partiesultimately signing it, with the USDOE supporting it but not signing it. Senator Case did notparticipate in the hearing or the Stipulation process. (Transcript of June 20-2 1, 2011, publichearing, hereinafter Tr., p. 55.) Larsen provided a history of the Company’s filing, stating theCompany’s initial request for $97.9 million was broadly driven by [i] capital investments intransmission infrastructure and environmental control facilities, [ii] an increase in power costsrelated to increasing costs of coal, purchased power and reductions in wholesale sales revenuecredits, and [iii] an adjustment for RECs of approximately $16.7 million. He stated the RECshad been removed from base rates and were to be included as a tracker through the Energy CostAdjustment Mechanism (ECAM) consistent with a prior Commission decision. (Tr., pp. 56-5 7.)

81. Larsen then described the Company’s rebuttal case, which reduced the requestedrevenue requirement increase from $97.9 million to approximately $80.1 million, based onadditional information and more fully understood adjustments, including, but not limited to [i] anadjustment of about $3 million due to a change in the tax laws on bonus depreciation which

29 Docket No. 20000-384-ER-b

allowed 100% bonus depreciation on some new facilities, [ii) an adjustment of approximately$3.6 million driven by the Commission’s decision in the 2010 interjurisdictional allocationProtocol proceeding, and, [iii] a decrease to net power costs of approximately $5.8 million due tothe Company’s updating of the forward price curve. (Tr., pp. 57-58.)

82. Larsen described the various options considered by the parties in addressing theREC revenues, including incorporating them into base rates or including them in the ECAMfiling. Larsen explained how the parties ultimately crafted an innovative mechanism for thetreatment of RECs that would allow the Company to implement the Commission’s decision inthe ECAM in Docket No. 20000-363-EA-10 (Sub 363), but allow Rocky Mountain Power’scustomers the benefit of the RECs as an offset to the rate increase in this case. To implementthis, the Company developed Tariff Schedule 93 (Attachment D to the Stipulation) to pass backthe benefits of the RECs and SO2 allowance sales in the amount of approximately $16.7 millionas a line item on customers’ bills coincident with the rate increase driven by this case beginningSeptember 22, 2011. The $16.7 million was calculated after the REC revenues had beendiscounted by a small interest amount of 1.8% plus an adder of 1.5% that would be prepaid ordeducted to compensate the Company for the lost time value of money. (Tr., pp. 59-60; RMPExhibit 67, p. 20.)

83. Larsen further discussed the major adjustments to the Company’s rebuttal case asreflected in the Stzpulation at paragraph 7 that reduced the overall revenue increase to $61.3million, to be effective September 22, 2011. (Tr., p. 60.) Larsen noted the parties agreed to areturn on equity of 10% with an overall return on rate base of 8%, which resulted in a reductionof $7.7 million in revenue requirement from the Company’s rebuttal case figure. The otherspecific adjustments included: [i] a coal inventory adjustment of $536,000; [ii] a $915,000reduction to wages and benefits expense related to escalation of wage and benefit costs; [iii) anoperations and maintenance (O&M) escalation adjustment of approximately $1.4 million(compared to the Company’s rebuttal case); [iv) a $225,000 reduction related to the timing andnumber of startups of combined cycle generators that impact the modeling and forecasting ofpower costs in the GRID model; and [v] a downward adjustment in total Company base NPCs of$48 million from $1,351,000,000 to approximately $1,303,000,000. (Tr., pp. 61-63.) Larsenexplained that, even with this reduction, total Company net power costs have increased by $300million from the previous Wyoming general rate case. (Tr., p. 63.)

84. Larsen noted the parties agreed in the Stzpulation to support the Company’sadjustment related to the Kiamath Hydroelectric Settlement Agreement, contingent on enactmentof federal legislation and subject to possible challenge of those costs in future rate proceedings.(Tr., p. 64.) The parties also agreed to accept the amortization over four years of the deferred taximpact of changes to the deductibility of certain post-retirement prescription drug benefits. (Tr.,p. 64.) Larsen testified the impact of the stipulated adjustments resulted in a stipulated overallrevenue increase in this case of approximately $61.3 million, with an offset to take into accountREC and SO2 sales revenues of $16.7 million, resulting in a stipulated net revenue increase of$44,610,000, or an average increase of 7.87%. (Tr. p. 65.) Larsen also addressed R.C. Johnson’scomment, received at the Casper hearing on June 2, 2011, that the Company should explain itsrate case in terms a layman could understand. Larsen explained that the $61.3 million increase iscomprised of two major components: [i] an annual $12 million carrying charge that represents

30 Docket No. 20000-384-ER-b

the Company’s recovery on over $1.4 billion of investments it has made in wind projects,transmission and distribution lines, and environmental control facilities; and [ii] power costincreases of $48 million, with the remaining amount being related to operations, maintenance,salaries and other costs. (Tr., pp. 65-66.) Larsen explained that Wyoming has 142,000customers out of the Company’s total system of approximately 1.7 million customers, or about8% of total Company customers. However, approximately 114 Wyoming customers represent72% of the energy usage in the state, making total Wyoming usage 16% to 18% of thePacifiCorp total system. (Tr., pp. 66-67.) Larsen also explained that Wyoming is a growingcomponent of the Company’s overall system. While Wyoming customers pay 16% to 18% oftotal system costs, they also receive the benefits associated with the placement of significantinfrastructure, such as coal plants and mines, in the state. (Tr., p. 67.) Larsen noted that theCompany’s calculated Wyoming rate base was $1,782,038,353. (See, RMP Exhibit 67, ScheduleJKL-2Stip, p. 2 of 4.) For example, with regard to a PacifiCorp system asset located inWyoming, Wyoming consumers pay only 16% to 18% of the cost. The revenue responsibility forthese costs, should they be included in rate base, are spread among the various customer classesaccording to the usage so that each customer class pays only its fair share. Because largeindustrial customers constitute more than 50% of the Company’s loaded Wyoming they wouldpay more than 50% of Wyoming’s share of the asset’s cost.

85. Larsen explained the portions of the Stipulation dealing with major plantadditions, noting that the parties have all agreed that the Populus to Ben Lomond component ofthe Populus-Terminal transmission line and the significant investments the Company has madein environmental control projects are currently used and useful and prudent. (Tr., p. 68.) Larsenfurther explained that the parties raised concerns related to transmission investment andenvironmental control projects in future years and sought an opportunity to review those costsbefore the Company seeks recovery in a general rate case. Larsen explained that the processproposed in the Stipulation is to use the Certificate ofPublic Convenience and Necessity (CPCN)process for both transmission and pollution control investments located in Wyoming, and a nontraditional ratemaking approach allowed in W.S. § 37-2-12 1 to enable the Commission to opineon the public interest aspects of investments in transmission facilities outside of the state. (Tr.,pp. 68-69.) He further stated that both types of applications would be filed if a transmissionproject segment were only partly located in Wyoming. (RMP Exhibit 67, p. 14.) It was Larsen’sopinion that the proposed CPCN and non-traditional ratemaking processes were covered by thebroad authority of the Commission. (Tr., p. 69.)

86. The Commission expressed concern that these proposed CPCN and nontraditional ratemaking processes provided for Commission preapproval of projects and theircosts in roughly the same manner as was seen in 2007 House Bill 12, that failed during thatlegislative session. Larsen opined that the language and provisions of failed House Bill 12 weredifferent from the processes being proposed by the parties in this Stipulation. Larsen stated:

What we’re really asking the Commission to do is use the CPCN process or the nontraditional ratemaking to review the investments that we’re going to make and issue acertificate either to move forward with the construction under the CPCN process or anopinion that the investments we’re going to make are in the public interest, but it does notbind the Commission in any way in terms of the ratemaking treatment of the preapproval

31 Docket No. 20000-384-ER-b

of that asset. All it does is gives the parties an opportunity to have their say before theCommission, and if the Commission agrees with the company, we move forward with theinvestment, and parties then have given up their chance to challenge those investmentsbut for the situation where the costs are in excess of what we are presented (sic) in theCPCN or the non-traditional ratemaking dockets or if there’s evidence ofmismanagement of the actual costs that we incur from actually building those facilities.

So it’s really the parties have given up certain rights in exchange for the opportunity tochallenge those before we proceed. The Commission still has broad latitude and fullauthority to review those dockets, those investments in a traditional rate case setting.(Tr., pp. 115-116.)

87. Larsen disagreed with the statement of OCA witness Freeman that the parties areasking the Commission to preapprove the investments under the proposed procedure. Larsenstated, “The parties really have agreed to the preapproval of the asset. [Emphasis supplied.] Ifthey go through that process, they’ve had their due process to challenge the assets and theinvestments before they occur, but I don’t believe the Commission is preapproving any of theactual investment dollars.” (Tr., p. 117.)

88. Larsen testified to the cost of service and rate spread process, stating thatmovement away from the current methodology could have a dramatic impact among customerclasses, as addressed by several intervenors in their testimony. In the Stipulation, the partiesagreed to apply the Company’s rebuttal cost of service and rate spread to the adjustments in theStipulation and diminish each adjustment ratably to spread the $61.3 million increase. Theparties also agreed that the residential customer charge would remain at $20 and the two-tierblock rate design for residential customers would be retained. Larsen discussed the cost ofservice collaborative process the parties agreed to engage in, and stated the parties would reporton the results of the collaborative to the Commission by October 3, 2011. (Tr., p. 70.) Larsenalso addressed customer comments regarding demand charges, stating that these charges did notconstitute double taxation but were used to recover the fixed costs of having facilities in place toserve customers, with the energy charge component to recover the costs for the product actuallyused. He discussed how usage is tied to cost causation, and how pricing is based on usage andnot customer income. (Tr., pp. 70-71.)

89. Larsen discussed the reliability issues the Company and its customers have beenexperiencing in the Casper area, attributing some outages to work being undertaken on systemupgrades, and acknowledging the Company had not effectively communicated to its customersregarding these outages or taken additional steps to mitigate some of these outages. (Tr., pp. 73-74.) Larsen discussed remedial plans contained in the Stzulation, which include [i] a 2011-2015capital improvement plan; an additional $3.1 million in funding (beyond the $4 million alreadyincluded in the case) to be applied on projects in the Natrona County area as well as state-wide;[ii] specifically identified projects with implementation date commitments; [iii] new servicequality reporting obligations; [iv] quarterly meetings with local officials; and [v] a commitmentto participate in a detailed planning process to further develop a Natrona County Electrical Plan.Larsen also discussed the additional inspections the Company has committed to perform in theNatrona County area, and the process the Natrona County area parties will have available to


bring complaints directly to Company management before raising the same or similar issues withthe Commission. (Tr., pp. 73-77.) Larsen also commented on the Company’s efforts inaddressing reliability issues in other areas of the state, including the Rawlins and Pinedale areas.Rocky Mountain Power agreed that members of the Commission staff were welcome to attendthe quarterly meetings and acknowledged that the Natrona County area parties could bring anysubject of interest to the Commission’s attention as part of, or outside the context of, a rate caseproceeding.

90. Larsen explained the line extension policy changes found in the Stipulation: Theparties agreed to increase the residential line extension allowance from $1,000 to $1,300, and tokeep the non-residential line extension allowance at one times the expected annual revenue. (Tr.,p. 77.) Larsen also testified that the Company agreed in the Stipulation to begin a process ofidentif’ing the necessary rights-of-way and line route for a substation site located near theNatrona County airport and the Town of Bar Nunn. Additional plant facilities would beconstructed when certain triggers based on the size of the expected loads related to developmentin the area occurred. (Tr., pp. 77-79.)

91. Finally, Larsen explained [i] that the parties have agreed not to challenge the useof a test period forecasted 15 months beyond the month in which the Company’s next generalrate case is filed, [ii) the housekeeping changes made to tariffs, and [iii] the Company’sagreement to incorporate new information related to the establishment of the Demand Responsemarket, including demand response programs, if there are changes or new situations, orinformation in that area prior to filing in its next general rate case. (Tr., p. 79.)

92. Larsen concluded by discussing the benefits to all parties of reaching a settlement,including creating commitments and ratepayer benefits that might not otherwise be achievablethrough a fully litigated case. (Tr., p. .80.) Larsen opined that the Stipulation is in the publicinterest, and that each issue raised by the parties has been adequately addressed and fullyresolved through the settlement process. He termed the settlement a fair compromise whichaddresses the positions of the parties, sets up an innovative resolution for RECs and other issues,and provides a way to deal with future large investments being planned by the Company. (Tr.,pp. 80-81.) Larsen said the agreed-upon increase provides proper price signals to customers,allows the Company a reasonable opportunity to recover its costs and gives it the opportunity,although not a guarantee, to earn a reasonable rate of return. In addition, rates set on the basis ofthe Stipulation would allow the Company to continue to provide, safe, adequate, and reliableservice at reasonable prices.

93. Stephen Baron prefiled testimony on behalf of WIEC in support of theStipulation. (WIEC Exhibit 199.4.) He stated that WIEC believed the Stipulation was in thepublic interest and discussed some of the reasons why it should be approved by the Commission,in particular, the issues of rate spread, rate design and the allocation of revenue responsibilitybetween the various classes. He supported the Stzpulation ‘s use of the Company’s proposed ratespread and rate design which were developed from the Company’s cost of service studypresented in its rebuttal case, noting that it produced rates within the range of 99% to 101% ofthe cost of service for each service class. Baron testified that WIEC believes that the result isreasonable. (Tr., pp. 98-99.)

33 Docket No. 20000-384-ER-b

94. Baron testified he supported the use of the Company’s proposed cost allocation

methodology for purposes of settlement and the provision in the Stzpulation which establishes a

cost of service collaborative. He stated the collaborative process provides the parties an

opportunity to consider, evaluate and address the myriad of cost of service issues that had been

identified and advocated for in this case, as well as other cost of service issues that the parties

might offer during the collaborative process for possible use in future Company rate cases.

Baron stated that part of WIEC’s support for this provision stems from the fact that it provides a

less formal process allowing a more thorough and candid evaluation of the Company’s

methodologies as well as those offered by others in determining which method was most

appropriate on a going forward basis. He recommended the Commission approve the Stipulation

as a reasonable resolution of the issues presented. (Tr., pp. 99-100.)

95. Kevin C. Higgins prefiled testimony on behalf of WIEC in support of the

Stipulation, sunnnarizing that testimony at the public hearing. (WIEC Exhibit 199.3.) He stated

he believed the Stipulation reasonably resolves the matters addressed in the rate case and

produces a result that is in the public interest by minimizing the level of rate increase for

customers while still affording Rocky Mountain Power an opportunity to earn a reasonable

return on investment. Higgins also noted the Stzulation provides for a reasonable mechanism to

credit customers with the revenues from the sale of RECs and SO2 allowances. (Tr., p. 154-155.)

96. Higgins noted the Stipulation provides public interest benefits that would

otherwise be unobtainable, such as implementing a process to investigate and evaluate the full

scope of planned capital expenditures on extraordinary multiyear projects like the Energy

Gateway project and planned large environmental upgrades. It also established the collaborative

process to investigate a broad range of cost allocation methods. (Tr., p. 155.)

97. Higgins testified that the Stipulation provides for a net rate increase of $44.6

million which reflects a reasonable resolution of the specific disputed issues between [i] the

Company’s rebuttal request of approximately $80 million, [ii] OCA’s proposed rate increase of

approximately $68 million and [iii] WIEC’ s proposed rate increase using a forecasted test period

of approximately $30 million. He stated the Stipulation allows for a rate of return on rate base of

8%, and a return on equity of 10% which he believes are reasonable given the Company had

requested a ROE of 10.5%, the OCA recommended 9.5% and WIEC had recommended 9.75%.

Higgins stated he believed a rate of return on rate base of 8%, and the return on equity of 10%

will provide the Company a reasonable opportunity to earn the agreed-upon rate of return. (Tr.,

p. 156.) Higgins further noted that Rocky Mountain Power’s Wyoming-allocated rate base has

increased from $1.67 billion to $1 .782 billion as agreed to in the Stipulation. Higgins also

acknowledged that net power costs have increased to approximately $1.3 billion on a company-

wide basis. Higgins further testified WIEC supported the treatment of the Kiamath

Hydroelectric Project Settlement and the amortization of the Medicare tax deferral, but only for

purposes of this Stipulation. WJEC accepted the Populus to Ben Lomond component of the

Populus to Terminal transmission line and Rocky Mountain Power’s expenditures on

environmental controls in this rate case as prudently incurred investments that are used and

useful. (Tr., p. 158.) Higgins qualified his support for the various stipulated-to adjustments and

issues by stating that WIEC reserved the right to raise these adjustments and issues for


discussion in future proceedings. Higgins stated the proposed Schedule 93 mechanismestablished in the Stipulation for recognizing REC and SO2 credits in rates at roughly the sametime revenues from them are received by the Company, while providing the Company with anupfront payment to reflect the time value of money, was a reasonable resolution of this issue.(Tr.,p. 158.)

98. Finally, Higgins expressed his support for the Stipulation provisions whichprovide a process for considering future investments in the Energy Gateway project and certainmajor environmental upgrades as it provides the Commission with the ability to review themerits of these investments on a cost and benefit basis prior to the investments being undertaken.He addressed in detail his understanding of the CPCN and the non-traditional filings processesfor major investments and environmental upgrades described in the Stipulation. (WIEC Exhibit199.3, pp. 8-12.) He further expressed WIEC’s support for the Stipulation provisions which [i]provide for additional investment and expenditures to address service quality and reliabilityissues in the Natrona County area, [ii] address line extension issues, and [iii] the agreement touse a forecasted test period in the next rate case with the understanding that the forecasted testperiod will end no more than 15 months from the month in which the case is filed.. (WIECExhibit 199.3, pp. 12-13.) Finally, Higgins stated WIEC strongly supported the Stipulation andrequested the Commission’s approval. (Tr., p. 158-159.)

99. Wallace Trembath, Jr., prefiled testimony and testified on behalf of theGovernmental Intervenors and Granite Peak in support of the Stipulation. (Casper Exhibit 346and Granite Peak Exhibit 405.) Trembath’s testimony focused on the provisions of paragraphs19 through 29 of the Stipulation, which addressed the electric reliability and availability issuesraised by the Governmental Intervenors and Granite Peak. Trembath stated that, although hisinitial conclusions regarding the Company’s electrical system and service were negative, asreflected in the significant degradation of service since 2002, it was his observation that theCompany has been responsive and reasonable during the course of negotiations in arriving atreasonable solutions intended to upgrade power quality and reliability in the Natrona Countyarea. Trembath testified the Stipulation includes reasonable provisions that address additionalinvestment in the Company’s power delivery system in the Casper/Natrona County area that willimprove the reliability and dependability of electrical service to the Casper/Natrona Countyservice areas. (Tr., p. 171.) He identified major items agreed to by the Company to improvesystem reliability and capacity, including upgrading the 69 kV system to 115 kV, and additionalCompany investment of $3.15 million state-wide for identified projects. He further testified theStipulation will require [ij the Company to file quarterly reports and hold quarterly meetingswith the Governmental Intervenors; [ii] revisions to the line extension policy (which includedincreasing the residential customer line extension allowance to $1,300); [iii] agreement by theCompany to initiate new construction projects in the Bar Nunn and Natrona County Airport areasif certain identified load criteria are met; [iv] the Company’s new Network Upgrade Policywhich provides a more equitable allocation of line extension costs as between the Company anda developer; and [v] the Cost Allocation Policy (Attachment C to the Stzpulation) which providesthe methodology to be used by the Company in allocating line extension costs between theCompany and the line extension applicant. (Tr. pp. 172-179.)

100. Bryce J. Freeman, Ad.niinistrator of the OCA, supported the Stipulation in prefiled

35 Docket No. 20000-384-ER-b

testimony which he summarized at the public hearings. Freeman considered several features ofthe Stzulation to be especially important: [i] the reduction in the requested rate increase from$98 million to a net increase of $44.6 million; [ii] all parties agreed to the recovery through ratesof the large investments in that portion of the Gateway project under consideration in this caseand the environmental upgrades that were deemed to be prudent and reasonable; and [iii] thatthere will be discussion on a broader basis with regard to additional environmental andtransmission upgrades in the future. (Tr., pp. 183-185.) Freeman testified that there are positivesassociated with conducting a thorough review of major plant investments in advance ascontemplated in the Stipulation’s approach to CPCN filings and non-traditional filings. Hetherefore supported the St4ulation early examination procedures as a good resolution of theseissues. (Tr., pp. 185-187.) He stated this process provided a good solution to the past problemof not having a viable process in place to review the prudency of large investments prior toimplementation. (Tr., p. 211.) Freeman also praised the resolution of the service quality andreliability issues, including addressing load growth issues raised by other Intervenors —

especially the Governmental Intervenors. (Tr., pp 187-188.) Freeman clarified that, insupporting the new mechanism for review of major plant investments, he was not advocating anyform of prior cost approval by the Commission for these projects before they were built.

101. Freeman also testified that the two-tier, two-block rate design in the Stipulationgoes a long way toward protecting low-use and low-income customers, by imposing a largerpercentage increase on higher use customers, and sending proper pricing signals. (Tr., pp. 188-189.) Freeman observed that OCA in witness Backofen’s prefiled testimony raised what heconsidered appropriate cost allocation issues which will be explored and discussed as part of thecost of service collaborative provided for in the Stipulation. It will provide the parties with anopportunity to examine those issues and other issues related to cost of service, and to prepare areport that will be useful to the Commission in making its determinations in the next rate case.(Tr., pp. 189-190.)

Legal Standards Applicable In This Case

102. W.S. § 37-3-101 requires that “[all] rates shall be just and reasonable, and allunjust and unreasonable rates are prohibited.” Similarly, W.S. § 37-3-112, requires that:

The service and facilities of every public utility shall be adequate and safe and everyservice regulation shall be just and reasonable. * * * It shall be unlawful for any publicutility to make or permit to exist any unjust discrimination or undue preference withrespect to its service, facilities or service regulations.

103. The Commission has broad powers to inquire into the facts surrounding thedetermination of rates. They include W.S. § 37-2-119, which articulates the “used and useful”test and allows wide latiti.ide in the Commission s investigation of rate-related matters. It statesthat:

In conducting any investigation pursuant to the provisions of this act the commission mayinvestigate, consider and deteñnine such matters as the cost or value, or both, of theproperty and business of any public utility, used and useful for the convenience of the

36 Docket No. 20000-384-ER-b

public, and all matters affecting or influencing such cost or value, the operating statisticsfor any public utility both as to revenues and expenses and as to the physical features ofoperation in such detail as the commission my deem advisable; the earnings, investmentand expenditures of any such corporation as a whole within this state, and as to rates inplant of any water, electrical or gas corporations, the geographical location thereof shallbe considered as well as the population of the municipality in which such plant is located.

104. W.S. § 37-2-122(a) reinforces the Commission’s discretion in rate making cases.It states:

In determining what are just and reasonable rates the commission may take intoconsideration availability or reliability of service, depreciation of plant, technologicalobsolescence of equipment, expense of operation, physical and other values of the plant,system, business and properties of the public utility whose rates are under consideration.

105. W.S. § 37-2-120 requires the Commission to afford due process in its cases,stating that:

[n]o order, however, shall be made by the commission which requires the change ofany rate or service, facility or service regulation except as otherwise specificallyprovided, unless or until all parties are afforded an opportunity for a hearing inaccordance with the Wyoming Administrative Procedure Act.

106. At W.S. § 16-3-107, the Wyoming Administrative Procedure sets parameters fordue process in Commission cases, including the giving of reasonable notice. In accord are W.S.§ 37-2-201, 37-2-202, and 37-3-106. See also, Sections 106 and 115 of the Commission’sRules.

107. W.S. § 37-2-122(b) gives necessary latitude to the Commission regarding utilityservices, stating that:

If, upon hearing and investigation, any service or service regulation of any public utilityshall be found by the commission to be unjustly discriminatory or unduly preferential, orany service or facility shall be found to be inadequate or unsafe, or any service regulationshall be found to be unjust or unreasonable, or any service, facility or service regulationshall be found otherwise in any respect to be in violation of any provisions of this act, thecommission may prescribe and order substituted therefore such service, facility or serviceregulation, as it shall determine to be adequate and safe, or just and reasonable, as thecase may be and otherwise in compliance with the provisions of this act, including anyprovisions concerning the availability or reliability of service. It shall be the duty of thepublic utility to comply with and conform to such determination and order of thecommission.

108. W.S. § 37-2-121 gives the Commission similar latitude to determine the actualrates to be charged by a utility and allows public utilities to present innovative regulatory forms,policies, and rate making methods, stating, that:

37 Docket No. 20000-384-ER-b

If upon hearing and investigation, any rate shall be found by the commission to beinadequate or unremunerative, or to be unjust, or unreasonable, or unjustlydiscriminatory, or unduly preferential or otherwise in any respect in violation of anyprovision of this act, the commission may fix and order substituted therefor such rate as itshall determine to be just and reasonable and in compliance with the provisions of thisact. Such rate so ascertained, determined and fixed by the commission shall be charged,enforced, collected and observed by the public utility for the period of time fixed by thecommission. The rates may contain provisions for incentives for improvement of thepublic utility’s performance or efficiency, lowering of operating costs, control ofexpenses or improvement and upgrading or modernization of its services or facilities.Any public utility may apply to the commission for its consent to use innovative,incentive or nontraditional rate making methods. In conducting any investigation andholding any hearing in response thereto, the commission may consider and approveproposals which include any rate, service regulation, rate setting concept, economicdevelopment rate, service concept, nondiscriminatory revenue sharing or profit-sharingform of regulation and policy, including policies for the encouragement of thedevelopment of public utility infrastructure, services, facilities or plant within the state,which can be shown by substantial evidence to support and be consistent with the publicinterest.

109. The Wyoming Supreme Court discussed the substantial evidence standard inMountain Fuel Supply Co. v. Public Service Corn ‘n of Wyoming, 1983 WY 39, 662 P.2d 878(Wyo. 1983). Because the substantial evidence standard is not commonly applied inadministrative proceedings but is routinely applied to administrative proceedings on appeal, wemust look to the Supreme Court’s discussion of the substantial evidence rule in the appellatecontext. In the Mountain Fuel Supply case, the Court stated, 1983 WY 39 atJ15:

For these cases [administrative appeals] we have adopted a definition of substantialevidence “as such relevant evidence as a reasonable mind might accept as adequate tosupport a conclusion.” Board of Trustees, Laramie County School District No. 1 v.Spiegel, supra, 549 P.2d at 1178, quoting Consolo v. Federal Maritime Commission, 383U.S. 607, 86 S.Ct. 1018, 16 L.Ed.2d 131 (1966). Such evidence may be less than theweight of the evidence, but cannot be clearly contrary to the overwhelming weight of theevidence. It is more than a mere scintilla of evidence or suspicion of a fact to beestablished. However, when our review of the whole record as required by § 9-4-114(c),W.S. 1977 (Cum.Supp. 1982) (now found at § 16-3-114(c), W.S. 1977, Oct. 1982 Rev.),leads the court to conclude that sufficient relevant evidence is present which a reasonablemind might accept as adequate to support the agency, then our examination is completed.[Citations omitted.] The burden of proving a lack of substantial evidence is upon theparty appealing the agency’s determination. [Editorial material supplied.]

110. The evidentiary areas standard which we must apply throughout our decisions,unless, as in the rare case of W.S. § 37-2-121, another standard is required, is the preponderanceof the evidence standard. This standard is not specifically set out in any of our controllingstatutes in Title 37, but the Wyoming Supreme Court has discussed the preponderance standard

38 Docket No. 20000-384-ER-b

and its applicability even when it is not specified in the relevant statute. In Willadsen v.Christopulos, 1987 WY 5, 731 P.2d 1181, (Wyo. 1987), the Wyoming Supreme Court discussedthe standard of proof to be used in Wyoming administrative hearings. Construing WyomingStatutes (W.S. § 41-3-911(b) and 41-3-911(c)), neither of which establishes a standard to beapplied in matters coming before the State Board of Control, the Supreme Court stated, 1987WY 5 at ¶13, with regard to W.S. § 41-3-911(c):

Under that statutory section and the applicable provisions of the Wyoming AdministrativeProcedure Act, the standard applicable to an adjudicatory hearing before the Board ofControl, unless otherwise stated, is the “preponderance of the evidence” standardcustomarily used in civil cases. Amerada Hess Pipeline Corporation v. Alaska PublicUtilities Commission, Alaska, 711 P.2d 1170, 1179 n. 14 (1986); Intermountain HealthCare, Inc. v. Board of County Commissioners of Blame County, Idaho, 107 Idaho 248,688 P.2d 260, 263 (1984), quoting E. Cleary, McCormick on Evidence § 357 (3d ed.1984).

Later, the Court emphasized the necessity of applying this standard, 1987 WY 5 at ¶14, saying:

Because the Board of Control failed to apply the preponderance of the evidence standardand instead applied the substantial evidence test applicable to appellate review of anagency decision, we find that petitioners were denied due process. As evidenced by theBoard of Control’s conclusions of law, petitioners not only had the burden of showing alack of substantial evidence for the decision of the State Engineer, but they also had thevirtually impossible task of proving conclusively that there was evidence of measurabledamage. The use of these standards at an evidentiary hearing violates due process.

Unlike the Willadsen case, one of the issues which we must decide — the matter of theapplications under W.S. § 37-1-12 1 regarding vetting of out-of-state projects as described in theStipulation — specifies the substantial evidence standard. Because the substantial evidencestandard set out in W.S. § 37-1-121 is the decisional standard we would apply in consideringsuch applications, we will apply the preponderance of the evidence standard as we considerapproving the basic framework of the innovative regulatory procedures under this statute asdescribed in the Stzpulation. Therefore, with respect to all issues in this case, we will apply thepreponderance of the evidence standard when assessing the degree to which Rocky MountainPower met its burden of proof. Given the mixture of issues in this case, we must be careful toavoid even colorably denying due process in any aspect thereof.

111. W.S. § 37-3-106 allows the Commission to suspend rates for a total of tenmonths, and places the burden of proof on the public utility to show the increased rates are justand reasonable. It states, in part:

(a) At any hearing as provided in this act involving an increase in rates or chargessought by a public utility, the burden of proof to show that the increased rate or charge isjust and reasonable shall be upon the utility.

39 Docket No. 20000-384-ER-b

(b) Unless the commission otherwise orders, no public utility shall make anychange in any rate which has been duly established except after thirty (30) days notice tothe commission, which notice shall plainly state the changes proposed to be made in therates then in force, and the time when the changed rates will go into effect. The utilityshall also give such notice of the proposed changes to other interested persons as thecommission in its discretion may direct. All proposed changes shall be shown by filingnew tariffs which shall be kept open to public inspection. When the commissionestablishes any rate which is innovative in form or substance, takes into considerationcompetitive marketplace elements or provides for incentives to a public utility, the ratemay contain any provision for subsequent notice or the absence thereof which issupported by the public interest.

(c) Whenever there is filed with the commission by any public utility anyapplication or tariff proposing a new rate or rates, the commission may, either uponcomplaint or upon its own initiative, initiate an investigation, hearing or both, concerningthe lawfulness of such rate or rates. Pending its decision thereon, the commission maysuspend such rate or rates, before they become effective but not for a longer initial periodthan six (6) months beyond the time when such rate or rates would otherwise go intoeffect. If the commission shall thereafter find that a longer time will be required, thecommission may extend the period of extension for an additional period or periods notexceeding in the aggregate, three (3) months.

112. Regarding an allowable rate of return, the Commission’s discretion must beguided by the earnings and capital attraction standards ofBluefield Water Works & ImprovementCo. v. Public Service Commission of West Virginia, 262 U. S. 679 (1923); and Federal PowerComm’n v. Hope Natural Gas Co. (Hope), 320 U. S. 391 (1944); accepted in Wyoming in In reNorthern Utilities, 70 Wyo. 225, 247 P.2d 767 (Wyo. 1952).

113. The public interest must come first in our decisions; and, as the WyomingSupreme Court has stated, the desires of the utility are secondary to it. Mountain Fuel SupplyCompany v. Public Service Comm ‘n, 662 P.2d 878 (Wyo. 1983). Construing W.S. § 37-3-101,which requires rates to be reasonable, the Court in Mountain Fuel, supra, at 883, commentedthat:

This court cannot usurp the legislative functions delegated to the PSC in settingappropriate rates, but will defer to the agency discretion so long as the results are fair,reasonable, uniform and not unduly discriminatory.

Later, 662 P.2d at 885, the Court in Mountain Fuel observed that:

We agree that if the end result complies with the ‘just and reasonable’ standardannounced in the statute, the methodology used by the PSC is not a concern of this court,but is a matter encompassed within the prerogatives of the PSC.

In accord are Great Western Sugar Co. v. Wyo. Public Service Comm ‘n and MDU, 624 P.2d1184 (Wyo. 1981); and Union Tel Co. v. Public Service Comm ‘n, 821 P.2d 550 (Wyo. 1991),

40 Docket No. 20000-384-ER-b

wherein the Supreme Court stated, 821 P.2d at 563, that it “...has recognized that discretion isvested in the PSC in establishing rate-making methodology so long as the result reached isreasonable.” Read in pan materia, these statutes articulate the basic mechanism of the publicinterest standard which the Commission is to follow in its decisions

114. Finally, Section 119 of the Commission’s Rules allows us to accept stipulations.It states: “. . . informal disposition may be made of any hearing by stipulation, agreed settlement,consent order or default upon approval of the Commission.”

Commission’s Review of Issues and Comments:The June 2, 2011, Public Comment Hearing

115. At the public comment hearing, R.C. Jones questioned what portion of thedemand charge is equated to a customer’s income and suggested that information be presented ina manner that the can be easily understood by the general public. The truth is that matters relatedto utility rate increases and how the amounts of those increases are determined is a complicatedprocess as evidenced by the Company’s application and the testimony of the various parties.Jones suggested the use of pie charts and graphs to help explain how rate increases aredetermined and costs allocated stating, “[t]he stuff you’re talking about is not, in case you didn’tknow it, rocket science. It can be distilled. It can be understood. It can be presented in a waythat anybody can understand.” (Comment Tr., p. 87, lines 21-24.) While the Commissionendeavors to keep the public informed of all aspects of a rate case and the impact it will have onall customer classes, the reality is, parts of a general rate case are extraordinarily technical andcomplex. Further, while Jones questioned demand charges to residential customers such asherself, there is no separately stated demand charge for residential customers, because there isrelatively little variation in usage or consumption patterns of residential customers. Therefore,residential customers pay one rate per kWh which includes a combined charge for consumptionand demand. Commercial and Industrial classes differ from the Residential class becauseelectricity use varies greatly between and among the Commercial and Industrial class members,some of whom place measurably larger requirements on the design and operation of the entiresystem. Meeting the electricity demands of some Commercial and Industrial customers requiresthe employment of expensive equipment capable of supplying enough electricity to meet thepeak demands of these two classes. To cover the costs of the equipment necessary to meet peakdemands of the Commercial and Industrial class, utilities generally spread these costs to theCommercial and Industrial class in the form of a demand charge.

Commission’s Findings of Fact

116. Many facts found by the Commission are set forth above and will not be repeatedhere. However, to provide context for our discussion of the case, we make three preliminarypoints.

117. First, this Commission generally refuses to embrace black box settlements, that is,settlements in which the parties have reached a result but have done so in a way which is opaqueto the Commission. If the Commission camiot generally comprehend how the parties went aboutreaching a settlement, and document the results in a way that permits comparisons with

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subsequent rate case applications, the Commission encounters great difficulty in fulfilling itsresponsibility to determine that the public interest has been served. At the same time,transparency alone does not satisfy the public interest. The Commission can and does rejectproposed settlements when it concludes they do not serve the public interest. E.g., MontanaDakota Utilities Co., Docket No. 20004-81-ER-109, May 26, 2010.

118. Second, this rate case is even more complex than meets the eye because it isinterlocked with other proceedings. A separate proceeding which allowed the Company to makeadjustments to its energy cOsts affects this case because the Commission requires the Companyto establish base net power costs in a general rate case such as this one, and because thevaluation and treatment of RECs will become a standard feature of energy cost adjustmentproceedings. Rocky Mountain Power, Docket No. 20000-368-EA-l0, February 4, 2011. Themethod by which the Company allocates multistate system costs among its state jurisdictionswas likewise the subject of a separate proceeding which directly affected the outcome in thiscase. Rocky Mountain Power, Docket No. 20000-381-BA-b, July 7, 2011. With the additionalcomplications of these interlocking dockets the Commission is keenly aware of the fact that theissues in a general rate case, and the resolution of those issues, are not always subject to simpleexplanation. Further, the operations of the electric grid itself are in fact akin to rocket science;such operations were tangentially involved in this case through the dispute over whether the newPopulus to Terminal transmission line was used and useful.

119. Third, the Commission has previously had occasion to generally consider thevirtues of stipulations, and to encourage parties to complex proceedings to participate insettlement discussions. Rocky Mountain Power, Docket Nos. 20000-352-ER-09 and 20000-363-EP-lO, July 29, 2010, paragraphs 135-140. Settlements of good quality most often save time andmoney for all engaged in the process; for example, we note that this case was scheduled for threefull weeks of hearings. A stipulation can produce a sound result in factually complexcircumstances, and in a way that permits all parties to achieve a generally favorable result.Stipulations can create commitments and ratepayer benefits that would be extremely difficult forthe Commission to order with useful practical effect. Settlement discussions can create value byallowing possible solutions to develop and be vetted more quickly than would be possible withan insistence on a contentious process.

120. Overall, the Commission finds the Stzpulation, with four supporting AttachmentsA—D, to be a well-documented explanation of how the parties propose to resolve the numerousissues in this case. We find that our adoption of the Stzulation would be in the public interest.The Stipulation responds to the broad array of issues raised in the extensive pre-filed testimony,does so in a way which reveals the main elements of the bargain reached by the parties, andprovides clear direction for Commission action.

121. The Stipulation satisfies the Commission’s concern for transparency in a varietyof ways. Broadly speaking, we see that issues that relate to accounting and modeling have beenbroken out so that we can see the detail of important accounting determinations, such as ratebase, and otherwise confirm that the parties reached a reasonable point of compromise, as is notgenerally the case with modeling issues. By way of major examples, we see that the partiesreached a complex yet reasonable solution to the problem of allocating tradable RECs between

42 Docket No. 20000-384-ER-b

this case and a future energy cost adjustment mechanism proceeding. The parties have addresseda deep concern for evaluating the prudence of major capital projects by proposing a marriage ofrevisions to our existing process for granting certificates of public convenience and necessity(CPCN) with our statutory authority for innovative ratemaking. The parties have addresseddifficult divisions regarding class costs of service by proposing a collaborative process for theparties to engage in further discussions, leaving in place for now the methods used in thepreceding rate case; this approach has ample and successful precedent in earlier Rocky MountainPower rate cases. The parties have addressed contentious reliability issues in Natrona Countywith a mixture of economic and procedural measures.

122. Some of the detail of the Stipulation will be of direct interest to the public atlarge. Attachment A to the Stipulation specifies the pollution control projects that would besubject to the innovative CPCN proceedings. Attachment B to the Stipulation, page 1, illustratesthe effect of the settlement on individual rate classes. Further calculations, beginning on page 10with the Residential class of customers, show how the rate increases will vary with usage for thevarious classes. In doing so, we note that the design of residential customer rates respond to theconcern of the OCA and AARP that greater energy usage should correspond with greaterpercentage increases, and note the assistance of the Company’s witness Griffith in preparing thecharts. Attachment C formally adopts a previously internal Company Cost Allocation Policywhich will facilitate planning by businesses interested in acquiring new service.

123. Attachment D explains how the REC and SO2 adjustment mechanism willoperate, and, in doing so, fits with all three of the Commission’s background concerns. First, itreduces to writing a significant aspect of the settlement which was largely an aspiration in thetestimony. The Commission and the parties know exactly what to expect for this case and thetransition to future energy cost adjustment mechanism proceedings. Second, Attachment Daddresses a complex interaction with an equally complex parallel docket, and solves a difficultywhich only emerged after the Commission had entered a final order in the previous docket.Third, Attachment D reaches a resolution which would have been difficult to hammer out in thecontext of a contested case hearing, even if the parties were broadly in agreement and does so ina way almost certainly more satisfactory to the parties than if the Commission had been facedwith broad disagreement.

124. The Commission finds the Stipulation broadly meets the second of its concerns,i.e., consistency with other dockets and with more complex features of the Company’s system.In addition to the contribution of Attachment D, the St4ulation includes a figure and supportingcalculations for base net power costs. The Stzpulation sets forth agreed details of rate base andthe Company’s capital structure. The Stipulation reflects and is consistent with theCommission’s ruling on allocation of costs between and among the state jurisdictions in whichRocky Mountain Power and Pacific Power operate. And, from a technical perspective, theStipulation is an appropriate settlement of claims that the Populus to Terminal transmission linewas not used and useful.

125. The Stipulation also illustrates the Commission’s interest in the value ofsettlement agreements, most significantly in the value of achieving results unlikely if the casewere decided simply on the merits of the parties’ positions. Rather than attempting to prescribe a

43 Docket No. 20000-384-ER-b

collaborative, which must be cooperative to be effective, the Commission would have ruled onclass cost of service issues based on the record made by the parties. Instead, the parties’ interestin a collaborative raises a reasonable hope that further discussion might lead to a result betterinformed by mutual understanding. At the very least, the Commission anticipates that class costof service issues will be better refined if they ultimately must be resolved by litigation. The.Commission’s interest in this collaborative is in the quality of the result rather than, strictlyspeaking, on the time the collaborators report is submitted. Therefore, upon application of theparties subsequent to our deliberation in this case, we acted by Letter Order to extend theOctober 3, 2011, report deadline called for in the Stipulation to October 31, 2011. The partiesrepresented to the Commission that this change of deadline dates would not be a materialalteration to the Stipulation.

126. Similarly, the Commission believes that the mixture of investment and newprocedures for cooperation will likely yield a better result for Natrona County than pursuing thecase to a final decision and unavoidably leaving the Company and the local governments in anadversarial position. As an aside, the Commission notes that the active intervention of the localgovernments in Natrona County created a more substantial record on Natrona County reliabilityissues than in previous proceedings, with the result that the settlement provides more substantialprogress than would have been justified by the record in previous proceedings.

127. Further, the Stipulation reaches a reasonable resolution to an unusually complexdispute among three experts regarding an appropriate Return on Equity.

128. The proposal for alterations to the CPCN process, limited to the projects listed inAttachment A, is surely a process that the Commission would not have proposed on its owninitiative. At the same time, we find it reasonable that the parties would express interest indevising a means to consider the prudence ofmajor capital investments before millions of dollarshave already been invested. While the proposed process does not require the Commission to preapprove such projects, it nonetheless represents a plausible innovation in the Commission’sreview of such projects, one that will provide value to the Company as well as to those interestedin exploring the merits of the proposed projects. The Commission finds sufficient merit in thisinnovative approach to support this element of the Stipulation. The Commission also recognizesthat for several parties, this element of the Stipulation was more important than any otherconsideration.

129. Pursuant to a commitment made by the Company during the proceedings, it mustreview Attachment C for the purpose of revising the definition of Main Grid Transmissionfacilities that are operated at or above 230 kV and Local Transmission facilities that are operatedbetween 46 kV and 230 kV, to reflect approved North American Electric Reliability Corporation(NERC) electrical system rules (including the developing definition of the Bulk ElectricalSystem) or other approved industry guidelines for transmission facility references after theCompany’s subject matter expert has an opportunity to research the matter. The Company shallalso file for Commission review any policy changes to Attachment C, the Company’s LineExtension Cost Allocation Policy.

44 Docket No. 20000-384-ER-b

130. In Paragraph 32 of the Stzpulation, the Company agrees to provide “testimonyregarding any new information, any analysis conducted by the company or any proposalsupported by the company, if any on demand response, monetizing demand or treating demandas a resource.” Since the Company has committed to provide testimony in its next general ratecase, if it does not put forth a proposal on demand response or monetizing demand response, itmust explain why it has chosen not to do so.

131. In its next general rate case application, for the purpose of informing theCommission regarding aspects of the Company’s transmission planning, the Commission directsthe Company to prepare and submit congestion charts, including at least a U95 chart and a U75chart, similar to those provided by Rocky Mountain Power witness Gerrard in his rebuttaltestimony.

132. Based on comments from Johnson and others at the Casper hearing on June 2,2011, the Commission notes that there is a significant misunderstanding concerning the demandcharge. The demand charge which was the subject of considerable controversy in the precedinggeneral rate case, decided July 29, 2010, does not apply to residential customers or to smallcommercial customers. It applies only to commercial customers whose use of electricity exceedsa prescribed level of intensity; the rationale for the charge is that these periods of intense userequire the Company to provide more capacity in its system than it does for residential or smallcommercial customers, thus increasing its fixed costs. The demand charge is accordingly ameans for reflecting a fair allocation of the Company’s costs between and among its customers.Further, customers who pay a demand charge pay considerably less for energy charges thanresidential and small commercial customers. In pre-filed testimony, the Company noted that theadjustments to the threshold for inclusion in the commercial class paying demand charges, madeby the Commission on its own initiative in the preceding rate case, have largely eliminatedcustomer complaints on this subject. Complaints to the Commission have likewise ceased.

133. The Commission finds the Stipulation is fundamentally sound. The agreementreached by the parties to the Stipulation results in a proposed base rate increase of $61.3 million,offset by $16.7 million of revenues from the sale of RECs and SO2 emission credits through anewly proposed tariff Schedule 93, for a proposed net increase of $44.6 million, or 7.87% onaverage. This result is reasonable and in the public interest.

134. Based upon our extensive review of the record in this case, including the prefiledtestimony, and the evidence presented at the hearing, the Commission finds, independent of theStipulation itself, that the Stipulation results in just and reasonable rates. The Stipulation, asmodified and with its Attachments A - D, is in the public interest and should be adopted andapproved.

Concinsions of Law

135. Rocky Mountain Power is duly authorized by the Commission to provide retailelectric public utility service in its Wyoming service territories under certificates of publicconvenience and necessity issued and amended by the Commission. Rocky Mountain Power isan electric public utility as defined in W.S. § 37-l-lOl(a)(vi)(C); and, as such, under W.S. § 37-

45 Docket No. 20000-384-ER-b

2-112, the Coniniission has the general and exclusive jurisdiction to regulate Rocky MountainPower as a public utility in Wyoming.

136. Proper public notice of these proceedings was given in accordance with theWyoming Administrative Procedure Act, W.S. § 3 7-2-203 and the Commission’s Rules,especially Section 106 thereof. The public hearings were held and conducted pursuant to theprovisions of W.S. § 16-3-107, 16-3-108, 37-2-203, and applicable sections of theCommission’s Rules. The interventions of the various parties were properly granted, and theentities and persons who intervened became parties to the case for all purposes. One interventionwas properly denied on the facts.

137. The preponderance of the evidence of record, as summarized herein, and asreflected in the Stipulation, supports the Commission’s conclusions that Rocky MountainPower’s current retail electric utility service rates in Wyoming are inadequate andunremunerative, and should be increased by a net amount of $44,610,000, as provided for in theStipulation, and to the extent provided for in this Order.

138. The Conmrission may approve a stipulation or agreed upon settlement as a meansof disposing of any matter coming before it at hearing pursuant to Commission Rule 119, andW.S. § 16-3-107(n) of the Wyoming Administrative Procedure Act.

139. Based upon its review of the Stipulation, as well as the testimony offered insupport of the Stipulation, the Commission concludes the provisions of the Stipulation discussedherein, and as set forth in Appendix A hereto, represents a just, equitable and reasonableresolution of all outstanding issues before the Commission in this proceeding. Therefore, theCompany should be granted a revenue increase, but only to the extent provided for in theStipulation and in this Order of a total of $61.3 million offset by $16.7 million of revenues fromthe sale of RECs and SO2 emission credits through a newly proposed tariff Schedule 93, effectiveSeptember 22, 2011. The additional revenue requirement as authorized herein shall be recoveredfrom the respective customer classes as set forth in the agreed upon rate spread and rate designproposals as proposed by the Company in its rebuttal testimony, and as illustrated in AttachmentB to the Stipulation. The recovery of Rocky Mountain Power’s costs, pursuant to the rate spreadand rate design proposals adopted herein, will not result in undue discrimination within orbetween customer classes as they are based on the respective cost of serving each customer classconsistent with W.S. § 37-3-112, and the Commission’s requirement that each class recoverbetween 99 % and 101% of its demonstrated class cost of service.

140. Consistent with the approved revenue requirement, the Commission’s findingsand the Stipulation, the Commission concludes a capital structure comprised of 47.4% debt,0.3% preferred stock, and 52.3% common equity, an authorized weighted cost of capital or rateof return on rate base of 8.0% and an authorized ROE of 10.0% for Rocky Mountain Power’sWyoming service territory operations are just and reasonable and in the public interest. Thisresult complies with the capital attraction standards of the Hope and BluejIeld cases, supra.

141. The Commission concludes that the rates approved herein are just and reasonable;produce no undue discrimination among customers, are adequate and remunerative, will allow


Rocky Mountain Power to continue to provide adequate, safe, and reliable service and to makeneeded investments in its Wyoming infrastructure.

142. The Commission further concludes the tariff modifications approved herein arejust and reasonable, supported by the evidence of record and should be approved as being in thepublic interest.

IT IS THEREFORE ORDERED:

1. Pursuant to the Commission’s deliberations held on June 21, 2011, the Stipulationand Agreement, with its Attachments, in the form appended hereto and incorporated herein byreference as Appendix A, is approved. Rocky Mountain Power is hereby authorized to increaseits rates to Wyoming customers in an amount consistent with the terms of this Order and theStipulation and Agreement. The increases in rates approved herein in the net amount of$44,610,000, (comprised of an increase of $61.3 million, offset by $16.7 million of revenuesfrom the sale of renewable energy credits and sulfur dioxide emission credits through a newlyproposed tariff Schedule 93), shall be effective for service provided on and after September 22,2011.

2. The additional revenue requirement as authorized herein shall be recovered fromthe respective customer classes as set forth in the agreed upon rate spread and rate designproposed by the Company in its rebuttal testimony, and as illustrated in Attachment B to theStipulation and Agreement.

3. All other terms and conditions set forth in the Stipulation and Agreement areapproved and incorporated into this Order.

4. The parties shall promptly hereinafter deal with all confidential information intheir possession in accordance with and at the time specified in the Confidentiality Agreementapproved by the Commission in its Protective Order dated February 9, 2011.

5. Any revised tariffs or rate schedules not afready approved by the Commissionshall be filed with the Commission for approval, consistent with the terms of this Order, withintwo weeks of its issuance.

6. This Order is effective immediately.

47 Docket No. 20000-384-ER10

MADE and ENTERED at Cheyenne, Wyoming, on September 22, 2011.

PUBLIC SERVICE COMMISSION OF WYOMING

AL B. MIME Chairman

-

STEVE XLEY, Deputy Chairm

KAJHLEEN A. LEWIS, Commissioner

DAVID J. LUCER9(Astant Secretary

48 Docket No. 20000-384-ER-b

Appendix A

Stipulation and Agreement, with Attachments A-DAs approved by the Wyoming PSC in Docket No. 20000-384-ER-lO


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