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HomeMy WebLinkAbout20100915Kelly Direct.pdfRECEI ium SEP i 5 AM 9= 34 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION In the Matter of the Application of ) PacifiCorp dba Rocky Mountain ) Power for Approval of Amendments to ) Revised Protocol Allocation )Methodology ) CASE NO. PAC-E-I0-09 Direct Testimony of Andrea L. Kelly ROCKY MOUNTAIN POWER CASE NO. PAC-E-I0-09 September 2010 1 Q.Please state your name, business address and present position with 2 PacifiCorp (the Company). 3 A.My name is Andrea L. Kelly, and my business address is 825 NE Mu1tnomah 4 Street, Suite 2000, Portland, OR 97232. lam curently employed as a Vice 5 President in Regulation. 6 Qualifications 7 Q.Please summarize your education and business experience. 8 A.I hold a Bachelor's degree in Economics from the University of Vermont and an 9 MBA in Environmental and Natual Resource Management from the University 10 of Washington. After graduate school, I joined the Staff of the Washington 11 Utilties and Transportation Commission. In 1995, I became employed by 12 PacifiCorp as a Senior Pricing Analyst in the Regulation Departent and 13 advanced through positions of increasing responsibility. From 1999 through 14 2005, I led major strategic projects at PacifiCorp including the Multi-State 15 Process (MSP) and the regulatory approvals for the MidAmerican-PacifiCorp 16 transaction. In March 2006, I was appointed as a Vice President in Regulation. 17 Q.Have you appeared as a witness in previous regulatory proceedings? 18 A.Yes, I have appeared as a witness on behalf of PacifiCorp in the states of 19 California, Idaho, Oregon, Utah, Washington, and Wyoming. 20 Purpose and Overview of Testimony 21 Q.What is the purpose of your testimony? 22 A.My direct testimony describes the process and approaches leading up to this fiing 23 of the proposed 2010 Protocol allocation methodology. Specifically, my direct Kelly, Di - 1 Rocky Mountain Power 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Q. 15 A. 16 testimony provides: . a brief history of the MSP leading up to the adoption of the Revised Protocol; . a brief history of the work of the Standing Committee workgroup since November 2008 that has culminated in this fiing proposing limited amendments to the Revised Protocol; . an overview of the proposed amendments to the Revised Protocol and the concerns that the amendments are designed to address; . a discussion of the Company's view of the commission proceedings necessary to process this application; and . a discussion of the Company's view of processes necessary to ensure successful implementation of the 2010 Protocol through calendar year 2016 and beyond. I also introduce the other two Company witnesses in this proceeding. Are you also sponsoring aD exhibit to your testimony? Yes. Exhibit NO.1 presents the 2010 Protocol with all of its Appendices. Although I sponsor Appendix A, Company witness Mr. Steven R. McDougal 17 sponsors the remaining Appendices. 18 Brief History of the Revised Protocol 19 Q. 20 21 A. 22 23 Please provide a brief history of the events that gave rise to the Revised Protocol. In December 2000, the Company proposed to reorganize itself into six state distrbution companies, a generation company and a service company. This Strctual Realignment Proposal (SRP) filing was in response to a number of Kelly, Di - 2 Rocky Mountain Power 1 2 3 4 5 6 7 8 Q. 9 A. 10 11 12 13 14 15 16 17 18 19 20 21 22 external developments, including: (1) the lack of agreement among regulatory jurisdictions regarding the Company's inter-jursdictional cost allocation process; (2) direct access initiatives in Oregon and elsewhere; (3) the need to provide independent control of transmission assets consistent with Federal Energy Regulatory Commission (FERC) expectations; (4) fudamental changes that occured in wholesale power markets; and (5) increasingly divergent policy goals of various state commissions. What was the outcome of the SRP filings? The SRP fiings proved to be controversial - in large measure because of a concern that the proposed restrcturng would result in a transfer of jurisdiction from state commissions to the FERC and the Securities and Exchange Commission. Ultimately, a number of parties and some state commissioners encouraged the Company to seek other means of resolving the Company's concerns that did not require a legal restrcturng of the Company. The Company was strongly encouraged to initiate an informal process aimed at achieving consensus among interested parties regarding a number of important issues facing the Company. To that end, in March 2002, the Company made an additional set of state filings asking the state commissions to initiate investigations and endorse a collaborative process to address inter-jurisdictional issues facing PacifiCorp. These fiings were broadly supported by the state commissions and gave rise to what became known as the MSP. Pending the MSP, the Company agreed to put the SRP fiings on hold. Kelly, Di - 3 Rocky Mountain Power 1 Q. 2 A. 3 4 5 6 7 8 9 10 11 12 13 14 15 Q. 16 A. 17 18 19 20 21 Q. 22 A. What occurred in the MSP? An initial organizing meeting was held in April 2002 in Boise, Idaho. At that first meeting, a schedule of futue meetings and objectives for the process were established. A number of additional MSP meetings were held through July 2003, after which the Company made an additional filing with the states seeking ratification of a proposed solution, the Protocol. Additional discussions related to the Protocol continued through September 2004, which resulted in the Company supplementing its filings with the Revised Protocol. Through commission proceedings, the four state commissions of Utah, Oregon, Wyoming and Idaho issued orders adopting the Revised Protocol in late 2004 and early 2005. Utah's and Idaho's adoption of the Revised Protocol was accompanied by rate mitigation mechanisms tied to the difference between the revenue requirement calculated under the Revised Protocol allocation methodology and the revenue requirement calculated under the Rolled-In allocation methodology. Who participated in the MSP collaborative meetings? All of the major meetings were attended in person by in excess of 50 individuals representing some 18 entities from the states of Utah, Oregon, Wyoming, Washington and Idaho. These included representatives of state commission policy staffs, advocacy staffs, industral customers and consumer groups. A number of other people participated by telephone. How would you characterize the overall objectives of the Revised Protocol? The objectives of the Revised Protocol include: Kelly, Di - 4 Rocky Mountain Power 1 2 3 4 5 6 7 8 9 10 11 Q. 12 13 A. 14 15 16 17 18 19 20 21 22 23 · allocating PacifiCorp's costs among its jursdictional states in an equitable manner; · ensuring PacifiCorp plans and operates its generation and transmission system on a six-state integrated basis in a maner that achieves a least cost-least risk resource portfolio for its customers; . allowing each state to independently establish its ratemaking policies. Each state is encouraged to consider the impact its decisions have on other states served by PacifiCorp; and · providing PacifiCorp a reasonable opportnity to recover 100 percent of its prudently incured costs. Does the Revised Protocol contain provisions for continued dialogue among the states? Yes. Section XIII.B of the Revised Protocol established the Standing Committee. While not abridging the integrity of commission decision-making processes within each respective state, the Standing Committee: . monitors and discusses inter-jurisdictional allocation issues facing PacifiCorp and its customers; · helps to organize and direct work group analysis of inter-jurisdictional allocation issues; . ensures work group analysis is supported by sound technical analysis; · shares views on possible amendments to the Revised Protocol, as they may arise; · seeks consensual resolution of issues arising under the Revised Protocol; Kelly, Di - 5 Rocky Mountain Power 1 . ensures wide dissemination of information regarding Standing Committee 2 meeting locations and dates and information relating to its activities; 3 . ensures and encourages open participation in Standing Committee meetings 4 by all interested persons; and, 5 . appoints the Standing Neutral to facilitate discussions among the states, to 6 monitor issues and to assist the Standing Committee. 7 Recent Activities of the Standing Committee 8 Q. 9 10 A. 11 12 13 14 15 16 17 18 19 20 21 22 23 Please provide an overview of the recent activities of the Standing Committee that led up to this fiing. At the November 2008 Commissioners' Forum, an issue was raised by Utah related to the performance of the Revised Protocol as compared against the forecast results at the time the Revised Protocol had been adopted. At that meeting, MSP participants reviewed a chart comparing the MSP 2005 forecast with the original MSP 2004 forecast. The char also provided comparisons to the Rolled-In allocation methodology both with and without the Utah rate mitigation measures. The chart raised concerns that Utah's expectations when adopting the Revised Protoco1- near-term costs but long-term savings for Utah customers as compared to Rolled-In - were not projected to be fulfilled. In response to this concern, at the Standing Committee Annual Meeting held in November 2008, the Company agreed to undertke a new forecast of results under the Revised Protocol using updated information from the upcoming 2008 Integrated Resource Plan which was to be filed in March 2009. The results were to be completed in suffcient time to be presented at the next annual Commissioners' Foru. As Kelly, Di - 6 Rocky Mountain Power 1 2 3 4 5 6 7 8 9 10 11 12 13 Q. 14 A. 15 16 17 Q. 18 A. 19 20 21 22 23 24 discussed in detail in the direct testimony of Mr. McDougal, the preliminary results of these studies were provided to parties on August 17, 2009. On August 27,2009, the Standing Neutral sent a request to parties for any new issues to be considered by the Standing Committee in preparation for the annual meeting scheduled for December 9,2009. On September 9,2009, several Utah parties issued a notification to MSP participants of the following issue: "Given review of the Company's August 17,2009, MSP Preliminar Study Results (2009 MSP Study) and the Public Service Commission of Utah's (PSCU) December 14,2004, Report and Order in Docket No. 02- 035-04, (MSP Order) the issue we raise is whether continued use of the revised protocol and rolled-in methods with rate mitigation measures is just and reasonable for PacifiCorp's Utah jursdiction." What action did the Standing Committee take in response to this issue? The Utah issue was first discussed by the Standing Committee at a meeting held on September 10, 2009. At the conclusion of the meeting, Utah parties were asked by the Standing Committee to develop a potential solution. What was the Utah parties' potential solution? At the September 24, 2009 Standing Committee meeting, Utah parties proposed a strawman solution that would eliminate seasonal and regional resource categories, limit the state resource category to demand-side management programs and state portfolio standard resource costs, and apply allocation factors for system resources to the resources formerly addressed in the seasonal, regional and state resource categories. In a nutshell, the strawran solution described a move to a Rolled-In allocation methodology. Kelly, Di - 7 Rocky Mountain Power 1 Q. 2 A. 3 4 5 6 7 8 9 Q. 10 11 A. 12 13 14 15 16 17 18 19 20 21 22 What potential solutions were considered subsequently? Over the next several months of Standing Committee meetings, participants considered the Utah parties' strawman solution, together with additional solution proposals offered for consideration by other MSP participants that focused on the elements of the Revised Protocol that could be analyzed as alternative considerations to address the Utah issue. At the direction of the Standing Committee, the Company provided quantitative analysis of the varous propos1s to aid the Standing Committee's deliberations and considerations. When was the first opportunity to inform and update the Commissioners of the work of the Standing Committee to address the issue? The Standing Committee convened a Commissioners' Forum in Portland, Oregon on Apri16, 2010. At that meeting, the Standing Committee updated Commissioners generally on the activities of the Committee since the previous Commissioners' Forum in November 2008. The Commissioners were also presented with the Utah issue, together with a summarization of the analyses performed and potential solutions considered. A concern raised was that the Utah issue, if insufficiently addressed, could cause states to depart from a consistent method of cost allocation and impair integrated system planning. After some consideration of the issues and materials presented, the Commissioners directed the Standing Committee to continue progress on analyzing potential solutions to resolve the Utah issue and requested a follow-up meeting for the summer of201O. In general, it was recognized that any solution would need to strke a balance Kelly, Di - 8 Rocky Mountain Power 1 2 3 Q. 4 5 A. 6 7 8 9 10 11 12 13 Q. 14 15 A. 16 17 18 19 20 21 22 between making progress toward fully Rolled-In allocations while maintaining a hydro endowment for Oregon and Wyoming. What was the progress of potential solutions prior to the next Commissioners' Forum? The Standing Committee and participants met for an additional six meetings to continue the quantitative analyses of potential solutions to the Utah issue. As well as analyzing potential solutions, the Standing Committee and participants analyzed the potential impacts of not being able to achieve a resolution acceptable to all states. These studies, known as the control area strctural separation and go-it-a10ne studies, were informative of the benefits of PacifiCorp continuing to operate as a single system. Progress since April 2010 was presented at the Commissioners' Foru held on June 13,2010. What direction was received from Commissioners at the forum held on June 13,2010? At the Commissioners' Forum held on June 13,2010, the Standing Committee updated Commissioners on the progress made since the previous meeting. The Commissioners expressed praise for the progress made and requested that the Standing Committee continue its efforts toward an acceptable resolution. An additional check-in meeting was targeted for July 2010. After the check-in, the Standing Committee developed a summary of what the members heard as guidance from the Commissioners. The summary included the following key points: Kelly, Di - 9 Rocky Mountain Power 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Q. 25 A. 26 27 28 29 30 31 32 1. All states prefer a consistent and fair cost allocation methodology that assures the Company a reasonable opportity to recover its costs and support fuher system investment. 2. Utah prefers the Rolled-In allocation methodology, or results stated as a deviation from the Rolled-In allocation methodology as a viable solution alternative. 3. Oregon and Wyoming Standing Committee members have considered pre- 2005 resource scenariosl as possible solution alternatives. 4. Both Wyoming and Oregon stressed that maintaining a hydro endowment is a critical component on any allocation methodology. 5. Utah stressed its benchmark methodology is Rolled-In and an allocation methodology should reflect Rolled-In +/- adjustments which are fixed for some futue time period so as to avoid a repeat of not achieving expected forecasted results. 6. The Commissioners have agreed that the Standing Committee should work with the Company to develop an updated analysis based on Wyoming - 1 results which could be used to establish a fixed amount per year per state as a deviation from the Rolled-In allocation methodology and is net of the situs assignment of the Klamath surcharge.. The results wil be presented for all years of the study and be accompanied by a disk with working spreadsheets. Assessing whether the Wyoming - 1 achieves essentially a Rolled-In result could be viewed from the perspective of treating the Klamath Settlement as Rolled-In. What actions did the Standing Committee take based on this guidance? Through additional conference calls and supporting analysis, the Standing Committee reached an agreement in principle that was presented on July 26,2010 at a fina1 Commissioners' Forum check-in conference call. The statement provided by the Standing Committee at that meeting stated: "Standing Committee participants of the MSP process have tentatively reached an agreement in principle changing the Revised Protocol cost allocation methodology. The initial premise for this new agreement is a Rolled-In cost allocation methodology. The changed methodology continues to identify State i "Pre-2005 resource scenaros" refers to the set of resources included in the "Aii-Other" category of the Embedded Cost Differential calculation. This is discussed in more detail in the direct testimony of Mr. McDougaL. Kelly, Di - 10 Rocky Mountain Power 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Q. 20 A. 21 22 23 24 Resources based on cost responsibility and Regional Resources for the Hydro Endowment calculation. Besides using Rolled-In as the starting point, a significant change relates to the Hydro Endowment quantified under the Embedded Cost Differential (ECD). The ECD wil be reduced and limited using. a comparison based on Pre-2005 Resources. It is proposed that for 2011 though 2016, the ECD calculation wil be projected and a fixed dollar amount per year deviation from Rolled-In analysis would be applied. The deviation is composed of two parts; (1) a situs adjustment charge for the Klamath Surcharge to Oregon and California, with a corresponding credit to the other states, and (2) an adjustment to reflect the Hydro Endowment ECD. State specific concerns continue to be evaluated and discussed. For instance: In Utah this cost allocation methodology produces results close to Rolled-In so a side agreement between the Company and Utah parties wil allow Utah to utilze Rolled-In cost allocation methodology for its ratemaking puroses. Forecast accuracy also continues to be evaluated by the other states, Oregon in particular, and may result in state specific measures to address the forecast risk related to fluctuations, up or down. Wyoming parties have an interest in addressing a concern about the Revised Protocol definition of State Resources." What was the outcome ofthe Commissioners' Forum held on July 26, 2010? At the Commissioners' Forum held on July 26,2010, the Standing Committee updated Commissioners that the group had reached an agreement in principle. Commissioners were informed that the Company hoped to fie an application in each state by mid-September 2010 initiating limited amendments to the Revised Protocol that would implement the terms of the agreement in principle. 25 Overview of Proposed Amendments 26 Q. 27 28 A. 29 30 31 In summary, what key concerns do the proposed amendments endeavor to address? As noted above, there were several overarching concerns expressed in the meetings: . The need to move more toward a Rolled-In allocation methodology to reflect system operations while retaining the hydro endowment in some form. Kelly, Di - 11 Rocky Mountain Power 1 2 3 4 5 Q. 6 7 A. 8 Q. 9 A. 10 11 12 Q. 13 A. . Volatility of results and unintended consequences of the ECD. . Unpredictabilty of reliance on forecasts. . Any solution must be fair to all states, and the Company must be afforded the opportnity to recover its prudently incured costs. Are the amendments proposed by the Company and supported by the Standing Committee consistent with this agreement in principle? Yes. The details are discussed in the direct testimony of Mr. McDougaL. Do the amendments exclusively address the Utah issue? No. The amendments also reflect an additional category of state resources called "state-specific initiatives". This addition includes emerging state-specific efforts to encourage investment in specific types of resources. Does this only include renewable resources? No. The category does not limit the tye of resource for which a state may seek 14 to encourage investment. 15 Process for Commission Review of Application 16 Q. 17 18 A. 19 20 21 22 23 What process does the Company propose for the Commission review of this Application? The Company is hopeful that the Commission wil be able to complete its review of this Application within a six-month timeframe. As discussed in the Company's direct testimony, significant analysis has been undertaken and reviewed by many parties since November 2008 as the Standing Committee considered its options. However, not all interested parties were able to participate in the Standing Committee efforts. As such, the Company proposes the following ilustrative Kelly, Di - 12 Rocky Mountain Power 1 schedule of milestones that would allow for discovery, rounds of testimony and 2 hearings that would allow sufficient time for a comprehensive record to be 3 developed upon which the Commission may base its decision: Event Date PacifiCorp Application, Testimony and Exhibits September 15,2010 Intervenor Testimony due Early-December 2010 PacifiCorp Rebuttal Testimony due Early-Januar 2011 Public Hearing Late-Januar 2011 Briefs due Mid-February 2011 Target Date for Commission Decision March31,2011 4 Q.Does the Company intend to continue dialogue with interested parties in each 5 state during the proceedings? 6 A.Yes. As noted in the Standing Committee's statement, the Company intends to 7 seek an agreement with Utah parties related to the use of the Rolled-In allocation 8 methodology and to work with Oregon parties to address forecast risk. The 9 Company wil also work to address any additional concerns that arise durg the 10 proceedings. It wil be imperative that any state-specific agreements do not 11 undermine the intent of the 2010 Protocol to allow PacifiCorp the reasonable 12 opportity to recover 100 percent of its prudently incured costs. 13 Processes subsequent to amendment adoption 14 Q.Assuming that the four state Commissions acknowledge the amendments and 15 adopt the 2010 Protocol, what ongoing processes does the Company envision 16 related to the 2010 Protocol? 17 A.As reflected in the 2010 Protocol, the Company is not proposing any changes to 18 the ongoing Standing Committee fuction at this time. Although the elements of 19 the 2010 Protocol are designed to minimize controversy and provide predictability Kelly, Di - 13 Rocky Mountain Power 1 through calendar year 2016, there are always emerging issues on which it is 2 valuable for states to continue to engage in discussions. 3 Q.What does the Company envision as a process to address allocation issues 4 post-2016? 5 A.The process would likely be similar to the one just followed. For example, the 6 post-20 16 issues would likely first be reviewed at the 2015 Standing COInittee 7 annual meeting. From that review, the Standing Committee would agree on 8 appropriate next steps as far as issue identifcation and analysis. Standing 9 Committee efforts would need to be designed to culminate in time for formal 10 commission proceedings to occur with decisions well in advance of January 1, 11 2017. It is also possible that the states would agree to extend the terms of the 12 2010 Protocol to apply beyond calendar year 2016. 13 Introduction of Witnesses 14 Q.Please introduce the Company's other witnesses and provide a brief 15 description of their testimony. 16 A.They are: 17 · Mr. Steven R. McDougal addresses the calculation and implementation of 18 the 2010 Protocol allocation methodology and presents the revenue 19 requirement analyses undertaken at the request of the Standing 20 Committee, and 21 . Mr. Gregory N. Duvall presents the net power cost (NPC) studies used to 22 support the 2010 Protocol revenue requirement analysis and to inform of 23 the Standing Committee's consideration of options. Kelly, Di - 14 Rocky Mountain Power 1 Q. 2 A. Does this conclude your direct testimony? Yes. Kelly, Di - 15 Rocky Mountain Power Case No. PAC-E-1O-09 Exhibit NO.1 Witness: Andrea L. Kelly BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION ROCKY MOUNTAIN POWER Exhibit Accompanying Direct Testimony of Andrea L. Kelly 2010 Protocol, including Appendices A to F September 2010 Rocky Mountain Power Exhibit NO.1 Page 1 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 1 2010 Protocol 2 I.Introduction 3 This 2010 PacifiCorp Inter-Jursdictional Cost Allocation Protocol (2010 4 Protocol) is the result of continuing discussions that have occurred among 5 representatives ofPacifiCorp, Commission staff members and other interested 6 paries from Utah, Oregon, Wyoming, and Idaho regarding issues arising from the 7 previously adopted Revised Protocol, and the Company's status as a multi- 8 jurisdictional utility. 9 PacifiCorp commits that it wil continue to plan and operate its generation 10 and transmission system on a six-State integrated basis in a manner that achieves a 11 least cost/least risk Resource portfolio for its customers. 12 The 2010 Protocol describes regulatory policies, which, if utilized by all 13 States for rate proceedings filed prior to January 1,2017, should afford PacifiCorp a 14 reasonable opportnity to recover all of its prudently incured expenses and 15 investments and ear its authorized rate of retu. The assignment of a particular 16 expense or investment, or allocation of a share of an expense or investment, to a 17 State pursuant to the 2010 Protocol is not intended to, and should not, prejudge the 18 prudence of those costs. Nothing in the 2010 Protocol shall abridge any State's right 19 and/or obligation to establish fair, just and reasonable rates based upon the law of 20 that State and the record established in rate proceedings conducted by that State. 21 Parties who have supported the ratification of the 2010 Protocol do so in the belief 22 that it wil continue to achieve a solution to multi state issues that is in the public 23 interest. However, a part's support of the 2010 Protocol is not intended in any 24 manner to negate the necessary flexibility of the regulatory process to deal with 2010 Protocol 1 Rocky Mountain Power Exhibit No. 1 Page 2 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 1 changed or unforeseen circumstances, and a part's support of the 2010 Protocol wil 2 not bind or be used against that part in the event that unforeseen or changed 3 circumstances cause that part to conclude, in good faith, that the 2010 Protocol no 4 longer produces results that are just, reasonable and in the public interest. Support of 5 the 2010 Protocol shall not be deemed to constitute an acknowledgement by any 6 par of the validity or invalidity of any paricular method, theory or principle of 7 regulation, cost recovery, cost of service or rate design and no part shall be deemed 8 to have agreed that any particular method, theory or principle of regulation, cost 9 recovery, cost of service or rate design employed in the 2010 Protocol is appropriate 10 for resolving any other issues. 11 The 2010 Protocol describes how the costs and wholesale revenues 12 associated with PacifiCorp's generation, transmission and distribution system wil be 13 assigned or allocated among its six-State jursdictions for puroses of establishing its 14 retail rates. 15 Definitions of terms that are capitalized in the 201 0 Protocol are set forth in 16 Appendix A. 17 A table identifying the allocation factor to be applied to each component of 18 PacifiCorp's revenue requirement calculation is included as Appendix B. 19 The algebraic derivation of each allocation factor is contained in Appendix C. 20 A description and numeric example of how Special Contracts and related 21 discounts wil be reflected in rates is set fort in Appendix D. 22 The fixed and 1eve1ized Embedded Cost Differential (ECD) amounts, that 23 wil be included in filings made through December 31, 2016, are set forth in 24 Appendix E. 2010 Protocol 2 Rocky Mountain Power Exhibit NO.1 Page 3 of 57 Case No. PAC-E-1Q-09 Witness: Andrea L. Kelly 1 Each State's allocated share of each Mid-Columbia Contract and the method 2 for calculating the shares is set forth in Appendix F. 3 II.Proposed Effective Date 4 The 2010 Protocol wil and apply to all PacifiCorp rate proceedings fied 5 prior to January 1, 2017. 6 7 III. Classifcation of Resource Costs 8 All Resource Fixed Costs, Wholesale Contracts and Short-term Purchases 9 and Sales wil be classified as 75 percent Demand-Related and 25 percent Energy- 10 Related. All costs associated with Non-Firm Purchases and Sales wil be classified 11 as 100 percent Energy-Related. 12 13 iv.Allocation of Resource Costs and Wholesale Revenues 14 Resources wil be assigned to one of three categories for inter-jursdictional 15 cost allocation puroses: 16 A. Regional Resources, 17 B. State Resources, or 18 C. System Resources. 19 There are two tyes of Regional Resource and four tyes of State Resources. 20 The remainder are System Resources which constitute the substantial majority of 21 PacifiCorp's Resources. Costs associated with each category and tye of Resource 22 wil be allocated on the following basis: 23 24 25 26 27 A.Regional Resources Costs associated with Regional Resources wil be assigned and allocated as follows: 1.Hydro-Endowment. 2010 Protocol 3 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 2010 Protocol Rocky Mountain Power Exhibit No. 1 Page 4 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly a.Owned Hydro Embedded Cost Differential Adjustment. The Owned Hydro Embedded Cost Differential Adjustment is calculated as follows: . The Forecasted Embedded Costs - Hydro-Electric Resources, less the Forecasted Embedded Costs- Pre-2005 Resources, multiplied by the normalized MWh's of output from the Hydro-Electric Resources. . The calculation is made using forecasted information contained in the Company's Baseline Study (fina1ized in March 2010) for calendar years 2011 through 2016. . The forecasted differential is allocated on the DGP factor and the inverse amount is allocated on the SG factor to compute State specific amounts for calendar years 2011 though 2016. . The net present value of the forecasted differential by State is set at a fixed dollar level that wil be used for all PacifiCorp rate proceedings filed prior b. to January 1,2017. Mid-Columbia Contract Embedded Cost Differential Adjustment. The Mid-Columbia Contract Embedded Cost Differential Adjustment is calculated as follows: . The Forecasted Mid-Columbia Contracts Costs, less the Forecasted Embedded Costs - Pre-2005 Resources, multiplied by the normalized MW's of 4 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 2. 25 26 27 2010 Protocol Rocky Mountain Power Exhibit No. 1 Page 5 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly output from the Mid-Columbia Contracts (Mid-C 1ess All Other). . The calculation is made using forecasted information contained in the Company's Baseline Study (fina1ized in March 2010) for calendar years 2011 through 2016. . The forecasted allocation of Mid-Columbia Contracts to each State is established pursuant to Appendix F. The forecasted Mid-Columbia differential is allocated on the MC factor and the inverse amount is allocated on the SG factor to compute State specific amounts for calendar years 2011 through 2016. . The net present value of the forecasted differential by State is set at a fixed dollar level that wil be used for all PacifiCorp rate proceedings fied prior to January 1,2017. The results of the Owned Hydro Embedded Cost Differential calculation and the Mid-Columbia Contract Embedded Cost Differential calculation are added together and a 1eve1ized annual value for the calendar years 2011 through 2016 time period is calculated. The 1eve1ized Hydro Endowment is fixed for puroses of ratemaking for that time period. Klamath Hydroelectric Settlement Agreement (KHSA). As part of futue ratemaking proceedings, the Company wil include the full impact of the KHSA as a system cost in unadjusted results. 5 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 B. 21 22 23 24 25 2010 Protocol Rocky Mountain Power Exhibit NO.1 Page 6 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly a. Klamath Dam Removal Surcharge Adjustment. The Klamath Dam Removal Surcharge is re-allocated to Oregon (92 percent) and California (8 percent) as follows: . Each State's initial allocated share of the Klamath Dam Removal Surcharge is reversed and assigned to Oregon and California on a situs basis. The calculation is made using forecasted information contained in the Company's Baseline Study (finalized in March 2010) for calendar years 2011 through 2016. . The net present value of the forecasted adjustment by State is set at a fixed dollar level that wil be used for all PacifiCorp rate proceedings fied prior to January 1, 2017. The 1eve1ized annual value for the calendar years 2011 through 2016 time period wil be used for puroses of ratemaking for that time period. State Resources Costs associated with the four tyes of State Resources wil be assigned as follows: 1.Demand':Side Management Programs: Costs associated with Demand-Side Management Programs wil be assigned on a situs basis to the State in which the investment is made. Benefits from these programs, in the form of reduced consumption and contrbution to peak, wil be reflected through time in the Load-Based Dynamic Allocation Factors. 6 Rocky Mountain Power Exhibit No. 1 Page 7 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 1 2.Portfolio Standards: Costs associated with Resources acquired 2 pursuant to a State Portfolio Standard, which exceed the costs 3 PacifiCorp would have otherwise incurred, wil be assigned on 4 a situs basis tothe State adopting the standard. 5 3.New Qualifying Facilities (QF) Contracts: Costs associated 6 with any New QF Contract, which exceed the costs PacifiCorp 7 would have otherwise incured acquiring Comparable 8 Resources, wil be assigned on a situs basis to the State 9 approving such contract. 10 4.State-Specific Initiatives: Costs associated with Resources 11 acquired pursuant to a State-specific initiative wil be assigned 12 on a situs basis to the State adopting the initiative. This 13 includes the costs of incentive programs, net-metering tariffs, 14 feed-in tariffs, capacity standard programs, electrc vehicle 15 programs and the acquisition of renewable energy certificates. 16 c.System Resources 17 All Resources that are not Regional Resources or State Resources are 18 System Resources. Generally, all Fixed Costs associated with System 19 Resources and all costs incurred under Wholesale Contracts wil be 20 allocated based upon the SG Factor. Generally, all Variable Costs 21 associated with System Resources wil be allocated based upon the 22 SE Factor. Revenues received by the Company pursuant to Wholesale 23 Contracts wil be allocated based upon the SG Factor. A complete 2010 Protocol 7 Rocky Mountain Power Exhibit NO.1 Page 8 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 1 2 3 4 5 6 7 8 9 10 11 12 V. description of the allocation factors to be utilized is set fort in D. Appendix B. Load Growth At the direction of the MSP Standing Committee, the Company and parties wil continue to analyze and quantify potential cost shifts related to faster-growing States.1 In addition, the MSP Standing Committee wil track key factors including actual relative growth rates, forecast relative growth rates, costs of new Resources compared to costs of existing Resources, and other factors deemed relevant to any potentia110ad growth-related issues. Refunctionalization and Allocation of Transmission Costs and Revenues 13 If the Company is required to refunctiona1ize assets that are curently 14 fuctionalized as "transmission" to "distribution", the cost responsibility for any 15 such refuctiona1ized assets wil be assigned to the State where they are located. Any 16 refunctiona1ization wil be implemented under the guidance of the MSP Standing 17 Committee. 18 Costs associated with transmission assets, and firm wheeling expenses and 19 revenues, wil be classified as 75 percent Demand-Related, 25 percent Energy- 20 Related and allocated among the States based upon the SG (System Generation) 21 factor. Non-firm wheeling expenses and revenues wil be allocated among the States 22 based upon the SE Factor. 23 1 This issue wil be monitored through studies that compute the costs allocated to each State for two cases: (a) with curently projected load growth together with a least-cost, least-risk mix of Resource additions to meet that growth and (b) with the fastest-growing State growing at the average growth projected for the remaining States, again with a least-cost, least-risk mix of Resource additions. 2010 Protocol 8 Rocky Mountain Power Exhibit No. 1 Page 9 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 1 VI.Assignment of Distribution Costs 2 All distribution-related expenses and investment that can be directly assigned 3 wil be directly assigned to the state where they are located. Those costs that cannot 4 be directly assigned wil be allocated among States consistent with the factors set 5 forth in Appendix B. 6 7 VII. Allocation of Administrative and General Costs 8 Administrative and general costs, costs of General Plant and costs of 9 Intangible Plant wil be allocated among States consistent with the factors set forth in 10 Appendix B. 11 12 VIII. Allocation of Special Contracts 13 Revenues associated with Special Contracts wil be included in State 14 revenues and loads of Special Contract customers wil be included in all Load-Based 15 Dynamic Allocation Factors. Special Contracts mayor may not include Customer 16 Ancilary Service Contract attibutes. In recognition that Special Contracts may take 17 different forms, Appendix D provides a wrtten description and numeric example of 18 the regulatory treatment of Special Contracts and associated discounts. 19 20 IX.Allocation of Gain or Loss from Sale of Resources or Transmission 21 Assets 22 Any loss or gain from the sale of a Resource (other than a Freed-Up 23 Resource) or a transmission asset wil be allocated among States based upon the 24 allocation factor used to allocate the Fixed Costs of the Resource or the transmission 25 asset at the time of its sale. Each Commission will determine the appropriate 26 allocation of loss or gain allocated to that State as between State customers and 27 PacifiCorp shareholders. 2010 Protocol 9 Rocky Mountain Power Exhibit NO.1 Page 10 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 1 2 X.Implementation of Direct Access Programs 3 A.Allocation of Costs and Benefits of Freed-Up Resources 4 1.Loads lost to Direct Access - Where the Company is required to 5 continue to plan for the load of Direct Access Customers, such 6 load wil be included in Load-Based Dynamic Allocation Factors 7 for all Resources. 8 2.Loads of customers permanently choosing Direct Access or 9 permanently opting out of New Resources - Where the Company 10 is no longer required to plan for the load of customers who 11 permanently choose direct access or permanently opt out of New 12 Resources, such loads wil be included in Load-Based Dynamic 13 Allocation Factors for all Existing Resources but wil not be 14 included in Load-Based Dynamic Allocation Factors for New 15 Resources acquired after the election to permanently choose 16 Direct Access or opt out of New Resources. An effective date for 17 this process wil be established at such time as customers 18 permanently choose Direct Access or opt out, and this process wil 19 be implemented under the guidance of the MSP Standing 20 Committee. 21 3.In each State with Direct Access Customers, an additional step 22 wil take place for ratemaking puroses to establish a value or cost 23 (which could include a transfer of Freed-Up Resources between 24 customer classes within a State) resulting from the departe of 25 the departing load; other States do not implement the second step. 26 B.Freed-Up Resource Sale Approval 2010 Protocol 10 Rocky Mountain Power Exhibit No. 1 Page 11 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 1 2 3 4 Any proposed sale of a Freed-Up Resource for purposes of calculating transition charges or credits wil be subject to applicable regulatory review and approval based upon a "no-harm" standard. States implementing Direct Access Programs that involve the sale of 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 XI. Freed-Up Resources wil endeavor to propose a method for allocating the gain or loss on a sale to Direct Access Customers in a manner that satisfies the "no-harm" standard in respect to customers in the other States. The parties agree that they wil not advocate a sale of Freed- Up Resources to be consummated if the proposed allocation of the gain or loss from the sale would cause the Company to distribute more than the total gain on a sale or recover less than the full amount of the tota110ss on a sale. c.Allocation of Revenues and Costs from Direct Access Purchases and Sales Revenues and costs from Direct Access Purchases and Sales wil be assigned situs to the State where the Direct Access Customers are located and wil not be included in Net Power Costs. Loss or Increase in Load 20 Any loss or increase in retai110ad occurng as a result of condemnation or 21 municipalization, sale or acquisition of new service terrtory which involves less than 22 five percent of system load, realignment of service terrtories, changes in economic 23 conditions or gain or loss of large customers wil be reflected in changes in Load- 24 Based Dynamic Allocation Factors. The allocation of costs and benefits arising from 25 merger, sale and acquisition transactions proposed by the Company involving more 26 than five percent of system load wil be dealt with on a case-by-case basis in the 27 course of Commission approval proceedings. 2010 Protocol 11 Rocky Mountain Power Exhibit NO.1 Page 12 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 1 2 XII. Commission Regulation of Resources 3 PacifiCorp shall plan and acquire new Resources on a system-wide least cost, 4 least risk basis. Prudently incured investments in Resources wil be reflected in 5 rates consistent with the laws and regulations in each State. 6 7 XIII. Sustainabilty of 2010 Protocol 8 A.Issues of Interpretation 9 If questions of interpretation of the 2010 Protocol arise durng rate 10 proceedings and/or audits of results ofPacifiCorp's operations, parties wil attempt 11 to resolve them with reference to the intent of the parties who have supported the 12 ratification of the 2010 Protocol. 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 B.MSP Standing Committee 1.The existing MSP Standing Committee wil continue to be organized consisting of one member or delegate of each Commission. The chair of the MSP Standing Committee wil be elected each year by the members of the Committee. The MSP Standing Committee wil appoint a Stading2. Neutral, at the Company's expense, to faciltate discussions among States, monitor issues and assist the MSP Standing Committee. 3.At least once during each calendar year, the Standing Neutral wil convene a meeting of the MSP Standing Committee and interested parties from all States for the purpose of discussing and monitoring emerging inter-jurisdictional issues facing the Company and its customers. The meetings wil be open to all interested parties. 2010 Protocol 12 Rocky Mountain Power Exhibit NO.1 Page 13 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 4.The MSP Standing Committee wil consider possible amendments to the 2010 Protocol that would be equitable to PacifiCorp customers in all States and to the Company. The MSP Standing Committee wil have discretion to determine how best to encourage consensual resolution of issues arising under the 2010 Protocol. Its actions may include, but wil not be limited to: a) appointing a committee of interested parties to study an issue and make recommendations, or b) retaining (at the Company's expense) one or more disinterested parties to make advisory findings on issues of fact arising under the 2010 Protocol. The work of the MSP Standing Committee wil be supported by sound technical analysis. A part supporting ratification of the 2010 Protocol wil work in good faith to address issues being considered by the MSP Standing Committee. 2010 Protocol Amendments 5. c. 17 Proposed amendments to the 2010 Protocol wil be submitted by 18 PacifiCorp to each Commission for ratification. The 2010 Protocol 19 wil only be deemed to have been amended if each of the 20 Commissions who have previously ratified the 2010 Protocol ratifies 21 the amendment. PacifiCorp wil not seek Commission ratification of 22 any amendment to the 2010 Protocol unless and until it has provided 23 interested paries with at least six months advance notice of its intent 24 to do so and endeavored to obtain consensus regarding its proposed 25 amendment. A part's initial support or acceptance of the 2010 26 Protocol wil not bind or be used against that part in the event that 27 unforeseen or changed circumstances cause that par to conclude that 2010 Protocol 13 Rocky Mountain Power Exhibit NO.1 Page 14 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 1 2 3 the 2010 Protocol no longer produces just and reasonable results. Prior to departing from the terms of the 2010 Protocol, consistent with their legal obligations, Commissions and parties wil endeavor to 5 6 7 cause their concerns to be presented at meetings of the MSP Standing Committee and interested parties from all States in an attempt to 4 achieve consensus on a proposed resolution of those concerns. D.Interdependency among Commission Approvals 8 The 2010 Protocol has been developed by the parties as an integrated, 9 inter-dependent, organic whole. Therefore, fina1 ratification of the 10 2010 Protocol by any of the Commissions of Oregon, Utah, Wyoming 11 and Idaho, is expressly conditioned upon similar ratification of the 12 2010 Protocol by the other mentioned Commissions, without any 13 deletion or alteration of a material term, or the addition of other 14 material terms or conditions. Upon any rejection of the 2010 15 Protocol, or any material deletion, alteration, or addition to its terms, 16 by anyone or more of the four Commissions, the Commissions who 17 have previously conditionally adopted the 2010 Protocol shall initiate 18 proceedings to determine whether they should reaffrm their prior 19 ratification of the 2010 Protocol, notwithstanding the action of the 20 other Commission or Commissions. The 2010 Protocol shall only be 21 in effect for a State upon final ratification by its Commission. The 22 Company wil continue to bear the risk of inconsistent allocation 23 methods among the States. 2010 Protocol 14 Rocky Mountain Power Exhibit NO.1 Page 15 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly APPENDIX A Rocky Mountain Power Exhibit No. 1 Page 16 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 2010 Protocol - Appendix A Defined Terms For puroses of this 2010 Protocol, the following terms wil have the following meanings: "2010 Protocol" means this 2010 PacifiCorp Inter-Jursdictional Cost Allocation Protocol. "Baseline Study" means the calculation of the Company's projected revenue requirement for calendar years 2010 through 2019 and the corresponding inter-jursdictional allocation. The Baseline Study was prepared in March 2010 and was designed to facilitate States' assessment ofthe ongoing reasonableness of the Revised Protocol. "Coincident Peak" means the hour each month that the combined demand of all PacifiCorp retail customers is greatest. In States using an historic test period, Coincident Peak is based upon actual, metered load data. In States using futue test periods, Coincident Peak is based upon forecasted loads. "Company" means PacifiCorp. "Commission" means a utility regulatory commission in a State. "Comparable Resource" means Resources with similar capacity factors, start-up costs, and other output and operating characteristics. "Customer Ancilary Service Contracts" means contracts between the Company and a retail customer pursuant to which the Company pays the customer for the right to curtail service so as to lower the costs of operating the Company's system. "Demand-Related Costs" means capital and other Fixed Costs incured by the Company in order to be prepared to meet the maximum demand imposed upon its system. "Demand-Side Management Programs" means programs intended to reduce electricity use through activities or programs that promote electrc energy efficiency or conservation, more efficient management of electrc energy loads, or reductions in peak demand. 2010 Protocol- Appendix A 1 Rocky Mountain Power Exhibit No. 1 Page 17 of 57 Case No. PAC-E-10.09 Witness: Andrea L. Kelly "nirect Access Customers" means retail electrcity consumers located in PacifiCorp's service terrtory that either: a) purchase electrcity directly from a supplier other than PacifiCorp pursuant to a Direct Access Program or b) elect to have all or a porton of the electrcity they purchase from PacifiCorp priced based upon market prices rather than the Company's traditional cost-of-service rate. If a State implements a Direct Access Program pursuant to which Freed-Up Resources are trnsferred between customer classes, such transfers shall be considered Direct Access Purchases and Sales. "Direct Access Program" means a law or regulation that permits retail consumers located in PacifiCorp's service terrtory to purchase electrcity directly from a supplier other than PacifiCorp. "Direct Access Purchases and Sales" means Wholesale Contracts and Short-Term Purchases and Sales entered into by PacifiCorp either to supply customers who have become Direct Access Customers or to dispose of Freed-Up Resources. "Energy-Related Costs" means costs, such as fuel costs that var with the amount of energy delivéred by the Company to its customers durig any hour plus any porton of Fixed Costs that have been deemed to have been incured by the Company in order to meet its energy requirements. "Existing Resources" means Resources whose costs were committed to prior to Direct Access Customers making an election to permanently forego being served by the Company at a cost-of-service rate. "FERC" means the Federal Energy Regulatory Commission. "Fixed Costs" means costs incured by the Company that do not var with the amount of energy delivered by the Company to its customers durng any hour. "Forecasted Embedded Costs - Hydro-Electric Resources" means PacifiCorp's total forecasted production costs contained in the Company's Baseline Study, for calendar years 2011 through 2016, expressed in dollars per MW, associated with Hydro-Electrc Resources as recorded in the FERC Accounts listed in Appendix E to the 2010 Protocol. 2010 Protocol - Appendix A 2 Revised - March 2, 2011 Rocky Mountain Power Exhibit No. 1 Page 18 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly "Forecasted Embedded Costs - Pre-2005 Resources" means PacifiCorp's total forecasted production costs ofPre-2005 Resources contained in the Company's Baseline Study, for calendar years 2011 through 2016, expressed in dollars per MW, other than costs associated with Hydro-Electrc Resources, and Mid-Columbia Contracts, as recorded in the FERC Accounts listed in Appendix E to the 2010 Protocol. "Forecasted Mid-Columbia Contract Costs" means the total forecasted net costs incured by PacifiCorp contained in the Company's Baseline Study, for calendar years 2011 though 2016, expressed in dollars per MW, under the Mid-Columbia Contracts. "Freed-Up Resources" means Resources made available to the Company as a result of its customers becoming Direct Access Customers. "General Plant" means capital investment included in FERC accounts 389 through 399. "Grant County"means Public Utility District NO.2 of Grant County, Washington "Hydro-Electric Resources" means Company-owned hydro-electrc plants located in Oregon, Washington or California. "Intangible Plant" means capital investment included in FERC accounts 301 though 303. "Klamath Dam Removal Surcharge" means the tariffs collected from customers in California and Oregon for the purose of providing fuding to remove specific Klamath River dams, as detailed in the Klamath Hydroelectrc Settlement Agreement. "Klamath Hydroelectric Settlement Agreement" means the Klamath Hydroelectrc Settlement Agreement executed on Februar 18,2010 for the purose of resolving specific FERC relicensing proceedings by establishing a process for potential facilties removal and operation of hydroelectric projects until that time. "Load-Based Dynamic Alocation Factor" means an allocation factor that is calculated using States' monthly energy usage and/or States' contrbution to monthly system Coincident Peak. 2010 Protocol - Appendix A 3 Revised - March 2, 2011 Rocky Mountain Power Exhibit No. 1 Page 19 of 57 Case No. PAe-E-10-09 Witness: Andrea L. Kelly "Mid-Columbia Contracts" means the Power Sales Contract with Grant County dated May 22, 1956; the Power Sales Contract with Grant County dated June 22, 1959;the Priest Rapids Project Product Sales Contract with Grant County dated December 31, 2001; the Additional Products Sales Agreement with Grant County dated December 31, 2001; the Priest Rapids Project Reasonable Portion Power Sales Contract with Grant County dated December 31, 2001; the Power Sales Contract with Douglas County PUD dated September 18, 1963; the Power Sales Contract with Chelan County PUD dated November 14, 1957 and all successor contracts thereto. "Net Power Costs" means PacifiCorp's fuel and wheeling expenses and costs and revenues associated with Wholesale Contracts, Seasonal Contracts, Short-Term Puchases and Sales and Non-Fir Purchases and Sales. "New QF Contracts" means Qualifying Facilty Contracts that are entered into subsequent to September 15, 2010. "New Resources" means Resources that are not Existing Resources as established pursuant to Paragraph XA2 of the 2010 Protocol. "Non-Firm Purchases and Sales" means transactions at wholesale that are not Wholesale Contracts, Seasonal Contracts, Short-Term Puchases and Sales or Direct Access Purchases and Sales. "Portfolio Standard" means a State law or regulation that requires PacifiCorp to acquire: (a) a particular tye of Resource, (b) a particular quantity of Resources, (c) Resources in a prescribed manner or (d) Resources located in a particular geographic area. "Pre-2005 Resources" means Resources (other than Mid-Columbia Contracts and Hydro-Electrc Resources) that were part of the Company's integrated system prior to Januar 1, 2005. "Qualifying Facilty Contracts" means contracts to purchase the output of small power production or cogeneration facilties developed under the Public Utility Regulatory Policies Act of 1978 (PURPA) and related State laws and regulations. 2010 Protocol - Appendix A 4 Revised - March 2, 2011 Rocky Mountain Power Exhibit No. 1 Page 20 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly "Resources" means Company-owned and leased generating plants and mines, Wholesale Contracts, Seasonal Contracts, Short-Term Purchases and Sales and Non-firm Purchases and Sales. "Short-Term Purchases and Sales" means physical or financial contracts pursuant to which PacifiCorp purchases, sells or exchanges firm power at wholesale and Customer Ancilary Service Contracts that are less than one year in duration. "Special Contract" means a contract entered between PacifiCorp's and one of its retail customers with prices, term and conditions different from otherwise-applicable tariff rates. Special Contracts may provide for a discount to reflect Customer Ancilary Services Contract attbutes. "Special Contract Ancilary Service Discounts" means discounts from otherwise applicable rates provided for in Special Contracts. "Standing Neutral" means an independent part, with experience in electrc utilty ratemaking, retained by the MSP Standing Committee to facilitate discussions among States, monitor issues and assist the MSP Standing Committee as required. "State Resources" means Resources whose costs are assigned to a single State to accommodate State-specific policy preferences. "System Resources" means Resources that are not Regional Resources, State Resources or Direct Access Purchases and Sales and whose associated costs and revenues are allocated among all States on a dynamic basis. "State" means Utah, Oregon, Wyoming, Idaho, Washington or California. "Variable Costs" means costs incured by the Company that vary with the amount of energy delivered by the Company to its customers during any hour. "Wholesale Contracts" means physical or financial contracts pursuant to which PacifiCorp purchases, sells or exchanges firm power at wholesale and Customer Ancilary Service Contracts. 2010 Protocol- Appendix A 5 Rocky Mountain Power Exhibit NO.1 Page 21 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly APPENDIXB 2010 Protocol- Appendix B Allocation Factor Applied to each Component of Revenue Requirement Rocky Mountain Power Exhibit No. 1 Page 22 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly FERC ACCT Sales to Ultimate Customers DESCRIPTION ALLOCATION FACTOR 440 Residential Sales Direct assigned - Jurisdiction S 442 Commeteial & Industrial Sales Direct assigned - Jurisdiction S 444 Public Street & Highway Lighting Direct assigned - Jurisdicton S 445 Other Sales to Public Authority Direct assigned - Jurisdiction S 448 Interdepartmental Direct assigned - Jurisdiction S 447 Sales for Resale Direct assigned - Jurisdiction Non-Firm Firm S SE SG 449 Provision for Rate Refund Direct assigned - Jurisdicton S SG Other Electric Operating Revenues 450 Forfeijed Discounts & Interest Direct assigned - Jurisdiction S 451 Mise Elecric Revenue Direct assigned - Jurisdiction Other - Common S SO 454 Rent of Electric Property Direc assigned - Jurisdicton Common Other - Common S SG SO 456 Other Elecric Revenue Direc! assigned - Jurisdiction Wheeling Non-firm, Other Common Wheeling - Firm, Other Customer Related S SE SO SG CN Miscellaneous Revenues 41160 Gain on Sale of Utilty Plant- CR Direct assigned - Jurisdiction Production, Transmission General Ofce S SG SO 2010 Protocol- Appendix B Allocation FERC ACCT 41170 4118 41181 421 Miscellaneous Expenses 4311 Steam Power Generation 500, 502, 504-514 501 503 Nuclear Power Generation 517 - 532 Hydraulic Power Generation 535 - 545 Other Power Generation 546, 548-554 547 Other Power Supply 555 2010 Protocol- Appendix B Rocky Mountain Power Exhibit NO.1 Page 23 of 57 Case No. PAC-E.10-09 Witness: Andrea L. KellyFactor Applied to each Component of Revenue Requirement DESCRIPTION ALLOCATION FACTOR Loss on Sale of Utility Plant Direct assigned - Jurisdiction Production, Transmission General Ofce S SG SO Gain from Emission Allowances S02 Emission Allowance sales SE Gain from Disposition of NOX Credits NOX Emission Allowance sales SE (Gain) I Loss on Sale of Utilty Plant Direct assigned - Jurisdiction Production, Transmission General Offce S SG SO Interest on Customer Deposits Utah Customer Service Deposits Direct assigned - Jurisdiction CN S Operation Supervision & Engineering Steam Plants SG Fuel Related Steam Plants SE Steam From Other Sources Steam Royalties SE Nuclear Power O&M Nuclear Plants SG HydroO&M Pacific Hydro East Hydro SG SG Operation Super & Engineering Other Production Plant SG Fuel Other Fuel Expense SE Purchased Power Direct assigned - Jurisdiction Firm Non-firm 100 MW Hydro Extension S SG SE SG 2 Rocky Mountain Power Exhibit No. 1 Page 24 of 57 Case No. PAC-E-10-09 Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement FERC ACCT DESCRIPTION ALLOCATION FACTOR 556 System Control & Load Dispatch Other Expenses SG 557 Other Expenses Direct assigned - Jurisdiction Other Expenses S SG 2010 Protocl Adjustments Hydro Endowment Klamath Dam Removal Surcharge Klamath Dam Removal Surcharge Re-allocation S S S TRANSMISSION EXPENSE 560-564, 566-573 Transmission O&M Transmission Plant SG 565 Transmission of Electricity by Others Firm Wheeling Non-Firm Wheeling SG SE DISTRIBUTION EXPENSE 580 - 598 Distribution O&M Direct assigned - Jurisdiction Other Distribution S SNPD CUSTOMER ACCOUNTS EXPENSE 901 - 905 Customer Accounts O&M Direct assigned - Juridiction Total System Customer Related S CN CUSTOMER SERVICE EXPENSE 907 - 910 Customer Service O&M Direct assigned - Jurisdicton Total System Customer Related S CN SALES EXPENSE 911 -916 Sales Expense O&M Direct assigned - Jurisdicton Total System Customer Related S CN ADMINISTRATIVE & GEN EXPENSE 920-935 Administrtive & General Expense Direct assigned - Jurisdiction Customer Related General FERC Regulatory Expense S CN SO SG DEPRECIATION EXPENSE 403SP Steam Depreciation Steam Plants SG 403NP Nuclear Depreciation Nuclear Plant SG 2010 Protocol- Appendix B 3 Rocky Mountain Power Exhibit No. 1 Page 25 of 57 Case NO.PAC-E-10-09 Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement FERC ACCT DESCRIPTION ALLOCATION FACTOR 403HP Hydro Depreciation Pacific Hydro East Hydro SG SG 4030P Oter Production Depreciation Other Production Plant SG 403TP Transmission Depreciation Transmission Plant SG 403 Distrbution Depreciation Direct assigned - Jurisdiction Land & Land Rights Structures Station Equipment Storage Battery Equipment Poles & Towers OH Conductrs UGConduit UG Conductor Line Trans Services Meters Inst Cust Prem Leased Propert Street Lighting S S S S s S S S S S S S S S 403GP General Depreciation Distribution Steam Plants Mining Pacific Hydro East Hydro Transmission Customer Related General SO S SG SE SG SG SG CN SO 403MP Mining Depreciation Remaining Mining Plant SE AMORTIZATION EXPENSE 404GP Amort of L T Plant. Capital Lease Gen Direct assigned - Jurisdicton General Customer Related S SO CN 404SP Amort of L T Plant - Cap Lease Steam Steam Production Plant SG 4041P Amort of L T Plant - Intangible Plant Distribution Production, Transmission General Mining Plant Customer Related S SG SO SE CN 2010 Protocol - Appendix B 4 Rocky Mountain Power Exhibit NO.1 Page 26 of 57 Case No. PAC-E-10-09 Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement FERC ACCT DESCRIPTION ALLOCATION FACTOR 404MP Amort of L T Plant - Mining Plant Mining Plant SE 404HP Amortization of Other Electric Plant Pacific Hydro East Hydro SG SG 405 Amortization of Other Electric Plant Direct assigned - Jurisdiction S 406 Amortization of Plant Acquisition Adj Direct assigned - Jurisdiction Production Plant S SG 407 Amort of Prop Losses, Unrec Plant, etc Direct assigned - Jurisdicton Production, Transmission Trojan S SG TROJP Taxes Other Than Income 408 Taxes Other Than Income Direct assigned - Jurisdiction Propert System Taxes Mise Energy Misc Production S GPS SO SE SG DEFERRED ITe 41140 Deferred Investment Tax Credit - Fed ITC DGU 41141 Deferred Investment Tax Credit - Idaho ITC DGU Interest Expense 427 Interest on Long-Term Debt Direct assigned - Jurisdicton Interest Expense S SNP 428 Amortization of Debt Disc & Exp Interest Expense SNP 429 Amortization of Premium on Debt Interest Expense SNP 431 Other Interest Expense Interes! Expense SNP 432 AFUDC . Borrowed AFUDC SNP 2010 Protocol - Appendix B 5 Rocky Mountain Power Exhibit No. 1 Page 27 of 57 Case No. PAC-E-10-09 Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement FERC ACCT Interest & Dividends DESCRIPTION ALLOCATION FACTOR 419 Interest & Dividends Interest & Dividends SNP DEFERRED INCOME TAXES 41010 Deferrd Income Tax - Federal-DR Direct assigned - Jurisdicton Electnc Plant in Service Pacific Hydro Production, Transmission Customer Related General Propert Tax related Miscellaneous Trojan Distnbution Mining Plant Bad Debt Tax Deprecia!ion S DITEXP SG SG CN SO GPS SNP TROJD SNF'D SE BADDEBT TAXDEPR 41011 Deferred Income Tax - State-DR Direct assigned - Junsdiction Electnc Plant in Service Pacific Hydro Producton, Transmission Customer Related General Propert Tax related Miscllaneous Trojan Distnbution Mining Plant Bad Debt Tax Depreciation S DITEXP SG SG CN SO GPS SNP TROJD SNPD SE BADDEBT TAXDEPR 41110 Deferred Income Tax - Federal-CR Direct assigned - Jurisdiction Electric Plan! in Servce Pacific Hydro Production, Transmission Customer Related General Propert Tax related Miscellaneous Trojan Distnbution Mining Plant Contnbutions in aid of construction Production, Other Book Depreciation S DITEXP SG SG CN SO GPS SNP TROJD SNPD SE CIAC SGCT SCHMDEXP 2010 Protocol- Appendix B 6 Rocky Mountain Power Exhibit NO.1 Page 28 of 57 Case No. PAC-E-10-09 Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement FERC ACCT DESCRIPTION ALLOCATION FACTOR 41111 Deferred Income Tax - Slate-CR Direct assigned - Jurisdicton Electric Plant in Service Pacific Hydro Production, Transmission Customer Related General Propert Tax related Miscellaneous Trojan Distribution Mining Plant Contributions in aid of constrction Production, Other Book Depreciation S DITEXP SG SG CN SO GPS SNP TROJD SNPD SE CIAC SGCT SCHMDEXP SCHEDULE. M ADDITIONS SCHMAF Additions - Flow Through Direct assigned - Jurisdiction S SCHMAP Additions - Permanent Direct assigned - Jurisdiction Mining related General Production J Transmission S SE SO SG SCHMAT Additions - Temporary Direct assigned - Jurisdiction Contributions in aid of construction Miscllaneous Trojan Pacific Hydro Mining Plant Producton, Transmission Propert Tax General Depreciation Distribution Production, Other S CIAC SNP TROJD SG SE SG GPS SO SCHMDEXP SNPD SGCT SCHEDULE - M DEDUCTIONS SCHMDF Deductons - Flow Through Direct assigned - Jurisdiction Production, Transmission Pacific Hydro S SG SG SCHMDP Deductions - Permanent Direct assigned - Jurisdiction Mining Related Miscellaneous General S SE SNP SO 2010 Protocol- Appendix B 7 Rocky Mountain Power Exhibit NO.1 Page 29 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly Allocation Factor Applied to each Component of Revenue Requirement FERC ACCT SCHMDT DESCRIPTION ALLOCATION FACTOR Deductons - Temporary Direct assigned - Jurisdicton Bad Debt Miscellaneous Pacific Hydro Mining related Proucton, Transmission Properl Tax General Depreciation Distrbution Customer Related S BADDEBT SNP SG SE SG GPS SO TAXDEPR SNPD CN State Income Taxes 40911 State Income Taxes (Internal calculation using blended statutory state and local income ta rate) S 40910 FIT True-up S 40910 Wyoming Wind Tax Credit SG Steam Production Plant 310-316 Steam Plants SG Nuclear Production Plant 320-325 Nuclear Plant SG Hydraulic Plant 330-336 Pacific Hydro East Hydro SG SG Other Production Plant 340-346 Other Producton Plant SG TRANSMISSION PLANT 350-359 Transmisson Plant SG DISTRIBUTION PLANT 360-373 Direct assigned - Jurisdicton S 2010 Protocol- Appendix B 8 Revised - March 2, 2011 Rocky Mountain Power Exhibit NO.1 Page 30 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly Allocation Factor Applied to each Component of Revenue Requirement FERC ACCT GENERAL PLANT 389 - 398 DESCRIPTION ALLOCATION FACTOR Distrbution Pacific Hydro East Hydro Proucton I Transmission Customer Related General Mining S SG SG SG CN SO SE 399 Coal Mine Remaining Mining Plant SE 399L WIDCO Capital Lease WIDCO Capital Lease SE 1011390 General Capital Leases Direct assigned - Jurisdicton General Proucton I Transmission S SO SG INTANGIBLE PLANT 301 Organization Direct assigned - Jurisdicton S 302 Franchise & Consent Direct assigned - Jurisdicton Producton, Transmission S SG 303 Miscellaneous Intangible Plant Distrbution Pacific Hydro East Hydro Production I Transmission Customer Related Generl Mining S SG SG SG CN SO SE 303 Less Non-Utility Plant Direct assigned - Jurisdicton S Rate Base Additions 105 Plant Held For Future Use Direct assigned - Jurisdicton Producton, Transmission Mining Plant S SG SE 114 Electric Plant Acquisition Adjustments Direct assigned - Jurisdicton Proucton Plant S SG 115 Accm Provision for Asset Acquisition Adjustments Direct assigned - Jurisdiction Producton Plant S SG 2010 Protocol-Appendix B 9 Revised - March 2, 2011 Rocky Mountain Power Exhibit NO.1 Page 31 of 57 Case No. PAG-E-10-09 Witness: Andrea L. Kelly Allocation Factor Applied to each Component of Revenue Requirement FERC ACCT ALLOCATION FACTORDESCRIPTION 120 Nuclear Fuel Nuclear Fuel SE 124 Weatherition Direct assigned - Jurisdiction General S SO 182W Weatherization Direct assigned - Jurisdiction S 186W Weatherization Direc assigned - Jurisdiction S 151 Fuel Stoc Steam Production Plant SE 152 Fuel Stock - Undistrbuted Steam Production Plant SE 25316 DG& T Worng Capital Deposit Mining Plant SE 25317 DG&T Working Capital Deposit Mining Plant SE 25319 Provo Working Capital Deposit Mining Plant SE 154 Materials and Supplies Direct assigned - Jurisdicton Producton, Transmission Mining General Producton - Common Hydro Distribution Production, Other S SG SE SO SG SG SNPD SG 163 Stores Expense Undistrbuted General SO 25318 Provo Working Capital Depoit Provo Working Capital Deposit SG 165 Prepayments Direct assigned - Jurisdicton Properl Tax Proucton, Transmission Mining General S GPS SG SE SO 2010 Protocol - Appendix B 10 Revised - March 2, 2011 Rocky Mountain Power Exhibit No. 1 Page 32 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly Allocation Factor Applied to each Component of Revenue Requirement FERC ACCT DESCRIPTION ALLOCATION FACTOR 182M Misc Regulatory Assets Direct assigned - Jurisdicton Production, Transmission Mining General Producton, Oter S SG SE SO SGCT 186M Misc Deferred Debits Direct assigned - Jurisdicton Production, Transmission General Mining Producton - Common S SG SO SE SG Working Capital CWC Cash Workng Capital Direct assigned - Jurisdicton S OWC Other Working Capital 131 Cash SNP 135 Working Funds SG 143 Other Accunts Receivable SO 232 Accunts Payable SO 232 Accounts Payable SE 253 Deferred Hedge SE 25330 Other Deferd Credits - Misc SE 230 Other Deferrd Credit - Misc SE Miscellaneous Rate Base 18221 Unrec Plant & Reg Study Costs Direct assigned - Jurisdicton S 18222 Nuclear Plant - Trojan Trojan Plant Trojan Plant TROJP TROJD 141 Notes Receivable Employee Loans - Hunter Plant SG Rate Base Deductions 235 Customer Service Deposits Direct assigned - Jurisdicton S 2281 Prov for Properl Insurance SO 2282 Prov for Injuries & Damages SO 2010 Protocol- Appendix B 11 Revised - March 2, 2011 Rocky Mountain Power Exhibit NO.1 Page 33 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly Allocation Factor Applied to each Component of Revenue Requirement FERC ACCT ALLOCATION FACTOR SO DESCRIPTION 2283 Prov for Pensions and Benefits 22841 Accum Misc Oper Prov-Black Lung Mining SE 22842 Accum Misc Oper Prov-Trojan Trojan Plant TROJD 254105 FAS 143 ARO Regulatory Liability Trojan Plant TROJP 230 Asset Retirement Obligation Trojan Plant TROJP 252 Customer Advances for Construction Direct assigned - Jurisdiction Producton, Transmission Customer Related S SG CN 25399 Other Deferred Credits Direct assigned - Jurisdiction Producton, Transmission Mining S SG SE 254 Regulatory Liabilties Regulatory Liabilties Insurance Provision SE SO 190 Accmulated Deferred Income Taxes Direct assigned - Jurisdiction Bad Debt Pacific Hydro Production, Transmission Customer Related General Miscellaneous Trojan Distribution Mining Plant S BADDEBT SG SG CN SO SNP TROJD SNPD SE 281 Accumulated Deferred Income Taxes Producton, Transmission SG 282 Accumulated Deferred Incoe Taxes Direct assigned - Jurisdicton Depreciation Hydro Pacific Producton, Transmission Customer Related General Miscellaneous Trojan Depreciation Depreciation S DITBAL SG SG CN SO SNP TROJP TAXDEPR SCHMDEXP 2010 Protocol - Appendix B 12 Revised - March 2, 2011 Rocky Mountain Power Exhibit No. 1 Page 34 of 57 Case No. PAC-E-10-09 Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement FERC ACCT DESCRIPTION ALLOCATION FACTOR 283 Accumulated Deferred Income Taxes Direct assigned - Jurisdiction Depreciation Hydro Pacific Production, Transmission Customer Related General Miscellaneous Trojan Production, Other Property Tax Mining Plant S DITBAL SG SG CN SO SNP TROJD SGCT GPS SE 255 Accumulated Investment Tax Credil Direct assigned - Jurisdiction Investment Tax Credits Investment Tax Credits Investment Tax Credits Investmen! Tax Credits Investment Tax Credits Investment Tax Credits Investmen! Tax Credits S ITC84 ITC85 ITC86 ITC88 ITC89 ITC90 DGU PRODUCTION PLANT ACCUM DEPRECIATION 108SP Steam Prod Plant Accumulated Depr Steam Plants SG 108NP Nuclear Prod Plant Accumulated Depr Nuclear Plant SG 108HP Hydraulic Prod Plant Accum Depr Pacific Hydro East Hydro SG SG 1080P Other Production Plant - Accum Depr Other Producton Plant SG TRANS PLANT ACCUM DEPR 108TP Transmission Plant Accumulated Depr Transmission Plant SG DISTRIBUTION PLANT ACCUM DEPR 108360 - 108373 Distribution Plant Accumulated Depr Direct assigned - Jurisdicion s 108DOO Unclassifed Dist Plant - Acc 300 Direct assigned - Jurisdiction s 108DS Unclassifed Dist Sub Plant - Acct 300 Direct assigned - Jurisdiction S 108DP Unclassifed Dist Sub Plant - Acct 300 Direct assigned - Jurisdiction S 2010 Protocol - Appendix B 13 Allocation Rocky Mountain Power Exhibit No. 1 Page 35 of 57 Case No. PAC-E-10-09 Witness: Andrea L. KellyFactor Applied to each Component of Revenue Requirement FERC ACCT GENERAL PLANT ACCUM OEPR 108GP General Plant Accumula!ed Depr Distribution Pacific Hydro East Hydro Production I Transmission DESCRIPTION ALLOCATION FACTOR Customer Related General SO Mining Plant Customer Related S SG SG SG CN SO SE CN 108MP Mining Plant Accumulated Depr. Mining Plant SE 108MP Less Centralia Situs Depreciation Direct assigned - Jurisdiction S 1081390 Accum Depr - Capital Lease General SO 1081399 Accum Depr - Capital Lease Direct assigned - Jurisdicton S ACCUM PROVISION FOR AMORTIZATION 111 SP Accum Prov for Amort-Steam Steam Plants SG 111GP Accum Prov for Amort-General Distrbution Pacific Hydro East Hydro Producton I Transmission Customer Related General SO S SG SG SG CN SO 111HP Accum Prov for Amort-Hydro Pacific Hydro East Hydro SG SG 1111P Accum Prov for Amort-Intangible Plant Distribution Pacific Hydro Producton, Transmission General Mining Customer Related S SG SG SO SE CN 1111P Less Non-Utiit Plant Direct assigned - Jurisdiction S 111399 Accum Prov for Amort-Mining Mining Plant SE 2010 Protocol ~ Appendix B 14 Rocky Mountain Power Exhibit NO.1 Page 36 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly APPENDIXC Rocky Mountain Power Exhibit NO.1 Page 37 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly u ~rI.-i:rI ===~Q ~.-=~Q .. Q. ..~M Q. CJ ~..~ ~.-ln~~ I ~..=~~..Q ~Q .-CJ iiCJ...-eQ~~..CJ ~~Q Q ii ..~..~Q.~..~eI ~..00=~~=M u .~ 1!Q) ~ i "8 ~¡io-oC' Al l o c a t i o n F a c t o r s Pa c i f i C o r p s e r v e s e i g h t ju r i s d i c t i o n s . J u r i s d i c t i o n s a r e r e p r e s e n t e d b y t h e i n d e x i = C a l i f o r n i a , I d a h o , O r e g o n , U t a h , W a s h i n g t o n , E a s t e r n Wy o m i n g , W e s t e r n W y o m i n g , & F E R C . Th e f o l l o w i n g a s s u m p t i o n s a r e m a d e i n t h e f a c t o r d e r i v a t i o n s : It i s a s s u m e d t h a t t h e 1 2 C P G = l t o 1 2 ) m e t h o d i s u s e d i n d e f i n i n g t h e S y s t e m C a p a c i t y ( " S C " ) . It i s a s s u m e d th a t t w e l v e m o n t h s G = l t o 1 2 ) m e t h o d i s u s e d i n d e f i n i n g t h e S y s t e m E n e r g y ( " S E " ) . In d e f i n i n g t h e S y s t e m G e n e r a t i o n ( " S G " ) f a c t o r , t h e w e i g h t i n g o f 7 5 p e r c e n t S y s t e m C a p a c i t y , 2 5 p e r c e n t S y s t e m E n e r g y i s a s s u m e d t o c o n t i n u e . Wh i l e i t i s a g r e e d t h a t t h e p e a k l o a d s & i n p u t e n e r g y s h o u l d b e t e m p e r a t u e a d j u s t e d , n o d e c i s i o n h a s b e e n m a d e u p o n t h e m e t h o d o l o g y t o d o th e s e a d j u s t m e n t s . Sv s t e m C a p a c i t y F a c t o r ( " S C " ) SC i !2 ¿T A P ¡ ¡ j= ! 8 ! 2 ¿¿ T A P ¡ ¡ ;= ! j = ! wh e r e : SC ¡ TA P i j Sy s t e m C a p a c i t y F a c t o r f o r j u r i s d i c t i o n i . Te m p e r a t u r e A d j u s t e d P e a k L o a d o f j u r i s d i c t i o n i i n m o n t h j a t t h e t i m e o f t h e S y s t e m P e a k . 20 1 0 P r o t o c o l - A p p e n d i x C 2 :: ( ' m : : ;: ~ ~ o i6 C D õ ' ~ g¡ Z ; : " C .. 0 Z s : 5' ~ 9 g Co ~ . . : : al ( ' \ l ! i II m i i : : r- ~ ~ " ' ;i l ' w ~ CD O o o C D ~ c o a . , oi.. Sy s t e m E n e n ! v F a c t o r ( " S E " ) SE i 12 ¿T A E ) )= 1 8 1 2 ¿¿ T A E ) i= 1 ) = 1 wh e r e : SE i TA E i j Sy s t e m E n e r g y F a c t o r f o r j u r i s d i c t i o n i . Te m p e r a t u r e A d j u s t e d I n p u t E n e r g y o f j u r i s d i c t i o n i i n m o n t h j . Sy s t e m G e n e r a t i o n F a c t o r ( " S G " ) SG i = . 7 5 * S C + . 2 5 * S E i wh e r e : SG i SC i SE ¡ Sy s t e m G e n e r a t i o n F a c t o r f o r j u r i s d i c t i o n i . Sy s t e m C a p a c i t y f o r j u r s d i c t i o n i . Sy s t e m E n e r g y f o r ju r i s d i c t i o n 1 . Mi d - C F a c t o r ( " M C " ) MC = W M C E . i= 8 i ¿W M C E . i= 1 i MC i = M i d - C F a c t o r f o r j u r i s d i c t i o n 1 . :: ( ) m : : ~ m ~ 0 ãl C D õ ' ~ g¡ z ; : ' - .. 0 z s : ;i ' 0 0 :: " U ' c : C. ; i . . : : ro ( ) " U ê : II r T I I : : r- ~ t g - u à C ? W 0 CD o c o : i a: ( O a ~ 01-. wh e r e : 20 I 0 P r o t o c o l - A p p e n d i x C 3 WM C E ¡ = E; r + ( E r r * S G i ) + ( E w a * W W A i ) + ( E w * S G i ) We i g h t e d M i d - C C o n t r a c t s a n n u a l e n e r g y g e n e r a t i o n wh e r e : E¡ : r = E ¡ p r I f i i s O r e g o n , o t h e r w i s e E¡ : r = 0 Ei p r = A n n u a l E n e r g y g e n e r a t i o n o f P r i e s t R a p i d s . Er r = Ew a = Ew = An n u a l E n e r g y g e n e r a t i o n o f R o c k y R e a c h . An n u a l E n e r g y g e n e r a t i o n o f W a n a p u m . An n u a l E n e r g y g e n e r a t i o n o f W e l l s . WW A i SG ~ i We i g h t e d W a n a p u m E n e r g y ¡= 8 IS G ¡ * ¡= 1 wh e r e : SG ¡ * = s a i f i i s W a s h i n g t o n o r O r e g o n j u r i s d i c t i o n , o t h e r w i s e SG ¡ * = 0 . SG ¡ = S y s t e m G e n e r a t i o n f o r j u r i s d i c t i o n 1 . Di v i s i o n G e n e r a t i o n - P a c i f c F a c t o r ( " D G P " ) DO P ¡ = S G ¡ * ¡: IS G ; ¡= 1 :; ( ) m : : ;: g j Š - 0 ãl C l ë ' ~ g¡ z ; : ' - .. 0 z ; S ". ' 0 0 :; - 0 ' i : a. ' " ~ : ; ø Ç " - o ~ Dl m D l : ; r~ ~ ' 1 A? " " ~ CI O O C l ~ c o a " " '".. wh e r e : DG P ¡ = D i v i s i o n G e n e r a t i o n - P a c i f i c F a c t o r f o r j u r s d i c t i o n 1 . 20 i 0 P r o t o c o l - A p p e n d i x C 4 SG i * = S G i i f i i s a P a c i f i c j u r i s d i c t i o n , o t h e r w i s e SG i * = O . SG ¡ = S y s t e m G e n e r a t i o n f o r j u r i s d i c t i o n i . Di v i s i o n G e n e r a t i o n - U t a h F a c t o r ( " D G U " ) DG ( J SG ~ i i= 8 IS G i * i= ! wh e r e : DG U ¡ = D i v i s i o n G e n e r a t i o n - U t a h F a c t o r f o r j u r i s d i c t i o n i . SG i * = S G i i f i i s a U t a h j u r i s d i c t i o n , o t h e r w i s e SG i * = O . SG ¡ = S y s t e m G e n e r a t i o n f o r j u r i s d i c t i o n i . :: o m ; o ;: D I X 0 ¡¡ i ß ~ ~ (J z ; : - - !' 0 z s : ~. 0 0 :i " U . c ci ~ . . : i al 0 " U i . Dl r n D l : i r~ ~ " ' à ' ? . ¡ ~ CD 0 " ' CD a: C D a . , ~ 20 1 0 P r o t o c o l - A p p e n d i x C 5 Re v i s e d - M a r c h 2 , 2 0 1 1 Rocky Mountain Power Exhibit No. 1 Page 42 of 57 Case No. PAG-E-10-09 Witness: Andrea L. Kelly ....oN N.. ~:: i"i~ ~ .,. i:0.-.,...u.-i:"00'".-.-..~u.-..."0 i-'"i..-i-;j i \0..... ..i-i:i:i.Cl Cl- -i.i: i:=i:i:-Cj 0 0=. .-.-.- .."E~i: ..,.=0._.- ='.c t:t:... u '"'"- .-.-.- = "0 CI CI,..;! i:i:... i-i. ;j 0 0~.~....-..... i- Cl Cl~ i. 'ü .-UI I lI lI - .. l5..i-0.= i: Q) i:lI= ClCl ClCl == ¡: "0 ¡: "0 i.~ i: li i: lio .. 0 ..=Z'- Cl._ Cl-.. -- ~ -- Cj e;j;j;j;j=Q;'ê§'ê§~ =~tiutiu..._ u._ u=tZCl-cci-c...-=,....i.- ~ --~~U...~X i Q Q ~-~ ~'l=8:=I I- ~~~ç$ Çi ~i=-ç$~Çi~õQ;'-~Z u II Q. ~ Q. ~B e 0 ~ .. Q;li i:i--Q)0~~....0tZ~N Sy s t e m G r o s s P l a n t - S y s t e m F a c t o r e G P S ~ ~ GP S i = i = 8 P P i + P T i + P D i + P G i + P I i L ( P P i + P T i + P D i + P G i + P L ) i= 1 GP - S ¡ pp ¡ PT ¡ PD t PG ¡ PI t Gr o s s P l a n t - S y s t e m F a c t o r f o r j u r i s d i c t i o n i . Pr o d u c t i o n P l a n t f o r j u r i s d i c t i o n 1 . Tr a n s m i s s i o n P l a n t f o r j u r i s d i c t i o n i . Di s t r i b u t i o n P l a n t f o r j u r s d i c t i o n i . Ge n e r a l P l a n t f o r j u r i s d i c t i o n 1 . In t a n g i b l e P l a n t f o r j u r i s d i c t i o n i . Sy s t e m N e t P l a n t F a ç t l ) ~ S N P " ) SN P i = i = 8 P P t + P T i + P D t + P G i + P I i - A D P P i - A D P T i - A D P D i - A D P G t - A D P I i L ( P P i + P T i + P D i + P G i + P L - A D P P i - A D P T i - A D P D i - A D P G i - A D P L ) i= 1 SN P ¡ = pp ¡ PT ¡ PD t PG ¡ PI t AD P P ¡ = AD P T ¡ = AD P D ¡ = AD P G ¡ = AD P I ¡ = Sy s t e m N e t P l a n t F a c t o r f o r j u r i s d i c t i o n i . Pr o d u c t i o n P l a n t f o r j u r i s d i c t i o n i . Tr a n s m i s s i o n P l a n t f o r j u r i s d i c t i o n i . Di s t r i b u t i o n P l a n t f o r j u r i s d i c t i o n 1 . Ge n e r a l P l a n t f o r j u r i s d i c t i o n 1 . In t a n g i b l e P l a n t f o r j u r s d i c t i o n i . Ac c u m u l a t e d D e p r e c i a t i o n P r o d u c t i o n P l a n t f o r j u r i s d i c t i o n i . Ac c u m u l a t e d D e p r e c i a t i o n T r a n s m i s s i o n P l a n t f o r j u r i s d i c t i o n i . Ac c u m u l a t e d D e p r e c i a t i o n D i s t r i b u t i o n P l a n t f o r j u r i s d i c t i o n i . Ac c u m u l a t e d D e p r e c i a t i o n G e n e r a l P l a n t f o r j u r s d i c t i o n i . Ac c u m u l a t e d D e p r e c i a t i o n I n t a n g i b l e P l a n t f o r j u r i s d i c t i o n 1 . ~( ) m ; ; ;: ~ ~ a 15 C D 5 ' f * (J z _ . - . (J . . .. 0 z š : 5' ~ ~ g a. : i ~ : i ei ( ) - o æ . II n i I I : i r ~ ~ - u ;i ' ? . i 0 CD o w : E = c o 0 ~ -. . . ~ 20 1 0 P r o t o c o l - A p p e n d i x C 7 Sy s t e m O v e r h e a d - G r o s s F a c t o r ( " S O " ) SO G i = i = 8 P P i + P T i + P D i + P G i + P l i - P P o i - P T o i - P D o i - P G o i - P l o i ~~ + n + ~ + ~ + f f - ~ i - ~ - ~ i - P ~ - ~ i= 1 SO G ¡ pp ¡ PT ¡ PD ¡ PG i PI ¡ PP o ¡ PT o ¡ PD o i PG o ¡ Pl o ¡ Sy s t e m O v e r h e a d - G r o s s F a c t o r f o r j u r i s d i c t i o n i . Gr o s s P r o d u c t i o n P l a n t f o r j u r s d i c t i o n i . Gr o s s T r a n s m i s s i o n P l a n t f o r j u r i s d i c t i o n i . Gr o s s D i s t r i b u t i o n P l a n t f o r j u r s d i c t i o n i . Gr o s s G e n e r a l P l a n t f o r j u r i s d i c t i o n i . Gr o s s I n t a n g i b l e P l a n t f o r j u r i s d i c t i o n i . Gr o s s P r o d u c t i o n P l a n t f o r j u r i s d i c t i o n i a l l o c a t e d o n a S O f a c t o r . Gr o s s T r a n s m i s s i o n P l a n t f o r j u r i s d i c t i o n i a l l o c a t e d o n a S O f a c t o r Gr o s s D i s t r i b u t i o n P l a n t f o r j u r i s d i c t i o n i a l l o c a t e d o n a S O f a c t o r Gr o s s G e n e r a l P l a n t f o r j u r i s d i c t i o n i a l l o c a t e d o n a S O f a c t o r Gr o s s I n t a n g i b l e P l a n t f o r j u r i s d i c t i o n i a l l o c a t e d o n a S O f a c t o r :E o m ; : ;: g ¡ ~ 0 ãl ( 1 _ . C ' 1I Z 2 : ~ 1I . . .. o z S : ): ' 0 0 :: " P ' c a. ) : . . : : ãl n " P ~ Dl m D l : : r- ~ ~ " t :: ' ? " " ~ (1 0 " " ( 1 a: c o a " " ~ 20 1 0 P r o t o c o l - A p p e n d i x C 8 Re v i s e d - M a r c h 2 , 2 0 1 1 Ba d D e b t E x p e n s e F a c t o r ( " B A D D E B T " ) BA D D E B 1 ì = A C C T 9 0 4 i i= 8 ¿: A C C T 9 0 4 i i= 1 BA D D E B T ; AC C T 9 0 4 i Ba d D e b t E x p e n s e F a c t o r f o r j u r i s d i c t i o n 1 . Ba l a n c e i n A c c o u n t 9 0 4 f o r j u r i s d i c t i o n 1 . Cu s t o m e r N u m b e r F a c t o r ( " C N " ) CN i = C U S T ¡ i= 8 ¿: C U S T . i= 1 i wh e r e : CN ; CU S T ; Cu s t o m e r N u m b e r F a c t o r f o r j u r s d i c t i o n i . To t a l E l e c t r i c C u s t o m e r s f o r j u r i s d i c t i o n i . Co n t r i b u t i o n s i n A i d o f C o n s t r u c t i o n ( " C I A C " ) CI A C = C I A C N A . i= 8 i ¿: C I A C N A . i= 1 i wh e r e : CI A C ¡ CI A C N A ¡ Co n t r i b u t i o n s i n A i d o f C o n s t r u c t i o n F a c t o r f o r j u r i s d i c t i o n i . Co n t r i b u t i o n s i n A i d o f C o n s t r c t i o n - N e t a d d i t i o n s f o r j u r i s d i c t i o n i . ~ á ? ~ ¡ s il l ß ~ ~ ~ z ; : :i ! = & = ~ :J " ' . c : ci ; i . . : J ø n - o P I Dl m D l : J r~ ~ " ' A' ? ' ¡ ~ (I 0 ( J ( I a: C O g , - ' (J-. 20 1 0 P r o t o c o l - A p p e n d i x C 9 Sc h e d u l e M - D e d u c t i o n s ( " S C H M D E X P " ) SC H M D E X P i = D E P R C i i= 8 LD E P R C . i= l i wh e r e : SC H M D E X P ¡ DE P R C ¡ Tr o j a n P l a n t ( " T R O J P " ) TR O J P i = i ¿ C C T 1 8 2 2 2 i L A C C T 1 8 2 2 2 . i= 1 i wh e r e : TR O J P ¡ AC C T 1 8 2 2 2 ¡ Sc h e d u l e M - D e d u c t i o n s ( S C H M D E X P ) F a c t o r f o r j u r i s d i c t i o n i . De p r e c i a t i o n i n A c c o u n t s 4 0 3 . 1 - 4 0 3 . 9 f o r j u r i s d i c t i o n i . Tr o j a n P l a n t ( T R O J P ) F a c t o r f o r j u r i s d i c t i o n i . Al l o c a t e d A d j u s t e d B a l a n c e i n A c c o u n t 1 8 2 . 2 2 f o r j u r i s d i c t i o n i . Tr o j a n D e c o m m i s s i o n i n g ( " T R O J D " ) TR O J D i = A C C T 2 2 8 4 2 . i 8 i "L A C C T 2 2 8 4 2 . i= 1 i wh e r e : TR O J D ¡ AC C T 2 2 8 4 2 ¡ 20 1 0 P r o t o c o l - A p p e n d i x C Tr o j a n D e c o m m i s s i o n i n g ( T R O J D ) F a c t o r f o r j u r i s d i c t i o n i . Al l o c a t e d A d j u s t e d B a l a n c e i n A c c o u n t 2 2 8 . 4 2 f o r j u r i s d i c t i o n i . ~ á 7 ~ ~ ~ l ß ~ ~ ø Z : : " ' . !' 0 Z š : ". " 0 0 :: " t " c : 0. ' " ~ : : al ( " " t i . mi i m : : r ~ ~ \ J A ' ? ~ ~ CD O O l C D a: c o a - ' gi 10 Re v i s e d - M a r c h 2 , 2 0 1 1 Ta x D e p r e c i a t i o n ( " T A X D E P R " ) TA X D E P R i = T A X E P R A i i 8 'L T A X E P R A . i= 1 i wh e r e : TA X E P R ¡ TA X E P R A ¡ Ta x D e p r e c i a t i o n ( T A X E P R ) F a c t o r f o r j u r i s d i c t i o n i . Ta x D e p r e c i a t i o n a l l o c a t e d t o j u r i s d i c t i o n i . (T a x D e p r e c i a t i o n i s a l l o c a t e d b a s e d o n f u c t i o n a l p r e m e r g e r a n d p o s t m e r g e r s p l i t s o f p l a n t u s i n g D i v i s i o n a l a n d Sy s t e m a l l o c a t i o n s f r o m a b o v e . E a c h ju r i s d i c t i o n ' s t o t a l a l l o c a t e d p o r t i o n o f Ta x d e p r e c i a t i o n i s d e t e r m i n e d b y i t s to t a l a l l o c a t e d r a t i o o f th e s e f u n c t i o n a l p r e a n d p o s t m e r g e r s p l i t s t o t h e t o t a l C o m p a n y T a x D e p r e c i a t i o n . ) De f e r r e d T a x E x p e n s e ( " D I T E X P " ) DI T E X P i = D I T E X P A . i- 8 . i 'L D I T E X P A . i= 1 i wh e r e : DI T E X P ¡ DI T E X P A ¡ 20 1 0 P r o t o c o l - A p p e n d i x C De f e r r e d T a x E x p e n s e ( D I T E X P ) F a c t o r f o r j u r i s d i c t i o n i . De f e r r e d T a x E x p e n s e a l l o c a t e d t o j u r i s d i c t i o n 1 . (D e f e r r e d T a x E x p e n s e i s a l l o c a t e d b y a r u o f P o w e r T a x b a s e d u p o n t h e a b o v e f a c t o r s . P o w e r T a x i s a c o m p u t e r so f t w a r e p a c k a g e u s e d t o t r a c k D e f e r r e d T a x E x p e n s e & D e f e r r e d T a x B a l a n c e s . P o w e r T a x a l l o c a t e s D e f e r r e d T a x Ex p e n s e a n d D e f e r r e d T a x B a l a n c e s t o t h e s t a t e s b a s e d u p o n a c o m p u t e r r u n w h i c h u s e s a s i n p u t s t h e p r e c e d i n g fa c t o r s . I f th e p r e c e d i n g f a c t o r s c h a n g e , t h e f a c t o r s g e n e r a t e d b y P o w e r T a x c h a n g e . ) 11 ~ ( " m : ; ;: e l ~ 0 15 ( I _ . ( ' tI . z 2 : ~ ti . . .. 9 z s : ~" U 9 g c. : i ~ = i aJ n - o ~ Ol m O l = i r~ ~ " ' A' ? ' ¡ 0 (I 0 - . ~ ~ c o a ' " 01-. " ~~~.. ~ :s- ~N CSoor ~ 1-.!!~.!! ~C.==-=~ =~ "C~i.i.~~~ :s- ~ t2Q II ~N CS .,. i:o.-t).--iv."§ . .~.~i- i: r. 0.-i. ..Cl .~ .. -iC. v.= .-~ ~-....~ 0~ ..~ 13~ ~.. Uas¿~ ~C. Q)= U= i:- Cd= -~ Cd~ a: = ~~ ~ "C -i ~ Q)!: i:~~~ Q) ~ Cl .~ ~.. .. ~ ~N N cs cs ~ ~ ~ ~ E- .. -i OJ 6. Q) .9 S .§ 13o Q) ßU 1' i- Cd 1- 0. v. v. Q).- Q).. ~ ~..'" U v.E- S¿ 'S ~ ~ g-o ~.-'" Cd v. .. E- Cd ~ ~ ~B ~ ;g ~ JS P-"B ~v.:. ã ~ 8 ~"B .g j ê ~Q)~ i-E-.. - Q) i-.. ~ .. Q) § ~ §. ~ 9--i ¡; P-.. Q) 0 "--i i: u..Q) Q) Cd-i ~ ~ i: Q)..Q)o.. ~ Cl 0. ~ Cd ~Y ;: Q)E- "' -i i:i- ~ ~ ~ ~ 5 ~ ~o 0. v. 0P-~Q)..c. ~.. Uo .s ~ ê ~ v. Q)L. Q)..L' .. .. Cd13..Q)~;:i:BOJ.. Q) v. i:-i~ Q)jgQ)Q)Uu~ Cl ã v.U ~ - i-o U Cd 0:: Cd a: t)Cd lj ~ ~ v. 0 Cd .- .. E- OJ8 -i -i.9i: Q) Q)-iCdv.i:Q)_;: UCdQ)~Q)a: ~)¿ l5~~I-Q)Cd U -i..E- Cd i: .. -i 0. Cd ~Q) Q) Q) i: a ~ v.~ ~ Q) i: Q) q; ~ t) a 55 ~ ~ Rocky Mountain Power Exhibit No. 1 Page 48 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly C".. u~:. i30.~ õuB £o- ~ Rocky Mountain Power Exhibit No. 1 Page 49 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly APPENDIXD Rocky Mountain Power Exhibit No. 1 Page 50 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 2010 Protocol - Appendix D Special Contracts Special Contracts without Ancilary Service Contract Attributes For allocation puroses Special Contracts without identifiable Ancilary Service Contract attbutes are viewed as one transaction. Loads of Special Contract customers wil be included in all Load-Based Dynamic Allocation Factors. When interrptions of a Special Contract customer's service occur, the reduction in load wil be reflected in the host jursdiction's Load-Based Dynamic Allocation Factors. Actual revenues received from Special Contract customer wil be assigned to the State where the Special Contract customer is located. See example in Table 1 Special Contracts with Ancilary Service Contract Attributes For allocation puroses Special Contracts with Ancilary Service Contrct attbutes are viewed as two transactions. PacifiCorp sells the customer electricity at the retail service rate and then buys the electrcity back durng the interrption period at the Ancilary Service Contract rate. Loads of Special Contract customers wil be included in all Load-Based Dynamic Allocation Factors. When interrptions ofa Special Contract customer's service occur, the host jursdiction's Load-Based Dynamic Allocation Factors and the retail service revenue are calculated as though the interrption did not occur. Revenues received from Special Contract customer, before any discounts for Customer Ancilar Service attbutes of the Special Contract, wil be assigned to the State where the Special Contract customer is located. Discounts from tariff prices provided for in Special Contracts that recognize the Customer Ancilar Service Contract attbutes of the Contrct, and payments to retail customers for Customer Ancilar Services wil be allocated among States on the same basis as System Resources. See example in Table 2 Buy-through of Economic Curtailment When a buy-through option is provided with economic curailment, the load, costs and revenue associated with a customer buying though economic curilment will be excluded from the calculation of State revenue requirements. The cost associated with the buy-though wil be removed from the calculation of net power costs, the Special Contract customer load associated with the buy-through wil be not be included in the calculation of Load-Based Dynamic Allocation Factors, and the revenue associated with the buy- through wil not be included in State revenues. 1 Rocky Mountain Power Exhibit NO.1 Page 51 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 2010 Protocol - Appendix 0 - Table 1 Interruptible Contract Without Ancilary Service Contract Attributes Effect on Revenue Requirement Factor Total system Jurisdiction 1 Jurisdiction 2 Jurisdiction 31 b2 2 Junsdictional Loads - No IntElrruptible Serviæ 3 Junsdictional Sum of 12 monthly CP demand (MW)72,000 24,000 36,000 12,000 4 Junsdictional Annual Energy (MWh)42,000,000 14,000,000 21,000.000 7,000,000 5 6 Junsdictional Loads - With Interruptible Service - Reflecting Actual Interruptions 7 Junsdictional Sum of 12 monthly CP demand (MW)71,700 24,000 35,700 12,000 8 Junsdictional Annual Energy (MWh)41,962,500 14,000,000 20,962,500 7,000,000 9 10 Special Contract Customer Revenue and Load - Non Interruptible Service 11 Special Contract Customer Revenue $20,000,000 $20,000,000 12 Special Contract Customer Sum of 12 CPs (MW) (Included in line 2)900 900 13 Special Contract Annual Energy (MWh) (Included in line 3)500,000 500,000 14 15 SpElcial Contract Customer Revenue and Load - Wilh Interruptible Servce (75 MW X 500 Hours of Interruption) 16 Special Contract Customer RevenuEl $16,000,000 $16,000,000 17 Discount for Ancillary Servces 18 Net Cost to Special Contract Customer $16,000,000 $16,000,000 19 Special Conlract Sum of 12 CP- Reflecting Actal Inlerruptions (MW) (Included in line 7)600 600 20 Special Contract Annual Energy- Reflecting Actual Interrptions (MWh) (Included in line 8)462,500 462,500 21 22 System Cost Savings from Interruption $4,000,000 23 24 Allocation Factors 25 No InterruptiblEl Serviæ 26 SE factor (Calculated from line 4)SEl 100.00%33.33%50.00%16.67% 27 SC factor (Calculated from line 3)SCL 100.00%33.33%50.00%16.67% 28 SG factor (line 27*75% + line 26'25%)SGl 100.00%33.33%50.00%16.67% 29 30 Wilh Interrptible Service (Reflectng Actual Physical Interrptions) 31 SE factor (Calculaled from line 8)SE2 100.00%33.36%49.96%16.68% 32 SC factor (Calculated from line 7)SC2 100.00%33.47%49.79%16.74% 33 SG factor (line 32'75% + line 31*25%)SG2 100.00%33.45%49.83%16.72% 34 35 36 No Interruptible Service 37 38 Cost of Service 39 Energy Cost SEl $500,000.000 $166,666,667 $250,000,000 $83,333,333 40 Demand Related Costs SGl $1,000,000,000 $333,333,333 $500.000,000 $166,666,667 41 Sum of Cost $1,500,000,000 $500,000,000 $750,000,000 $250,000,000 42 43 Revenues 44 SpElcial Contract RevElnuEl Situs $20,000,000 $20,000,000 45 Revenues from all other customel"Situs $1,480,000,000 $500,000,000 $730,000,000 $250,000,000 46 47 48 With Interruptible Service 49 50 Cost of Service 51 EnElrgy Cost SE2 $498,000,000 $166,148,347 $248,777,480 $83,074,173 52 Demand Related Costs SG2 $998,000,000 $334,058,577 $496,912,134 $167,029,289 53 Sum of Cost $1,496,000,000 $500,206,924 $745,689,614 $250,103,462 54 55 RElvenues 56 Special Contract Revenue Situs $16,000,000 $16,000,000 57 Revenues from all other customers Situs $1,480,000,000 $500,206,924 $729,689,614 $250,103,462 2010 Protocol - Appendix D 2 Rocky Mountain Power Exhibit No. 1 Page 52 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 2010 Protocol. Appendix D . Table 2 Interruptible Contract With Ancilary Service Contract Attributes Effect on Revenue Requirement Factor Total system Jurisdiction 1 Jurisdiction 2 Jurisdiction 3 1 Loads 2 Jurisdictional Loads - No Interruptible Service 3 Jurisdictional Sum of 12 monthly CP demand (MW)72,000 24,000 36,000 12,000 4 Jurisdictional Annual Energy (MWh)42,000,000 14,000,000 21,000,000 7,000,000 5 6 Jurisdictional Loads - With Interruptible Servce - Reflecting Actual Interruptions 7 Jurisdictional Sum of 12 monthly CP demand (MW)71,700 24.000 35,700 12,000 8 Jurisdictional Annual Energy (MWh)41,962,500 14,000,000 20,962,500 7,000,000 9 10 Special Contract Customer Revenue and Load - Non Interrptible Service 11 Special Contract Customer Revenue $20,000,000 $20,000,000 12 Special Contract Customer Sum of 12 CPs (MW) (Included in line 2)900 900 13 Special Contract Annual Energy (MWh) (Included in line 3)500,000 500,000 14 15 Special Contract Customer Revenue and Load. With Interrptible Service (75 MW X 500 Hours of Interruption) 16 Tariff Equivalent Revenue $20,000,000 $20,000,000 17 Ancilary Service Discount for 75 MW X 500 Hours of Economic Curtilment $(4,000,000)18 Net Cost to Special Contract Customer $16,000,000 $16,000,000 19 Special Contract Sum of 12 CP- Reflecting Actuallnterrplions (MW) (Included in line 7)600 600 20 Special Contract Annual Energy- Reflecting Actuallnlerruptions (MWh) (Included in line 8)462,500 462,500 21 22 System Cost Savings from Interrption $4,000,000 23 24 Allocation Factors 25 No Interrptible Service 26 SE factor (Calculated from line 4)SE1 100.00%33.33%50.00%16.67% 27 SC factor (Calculated from line 3)SC1 100.00%33.33%50.00%16.67% 28 SG factor (line 27*75% + line 26'25%)SG1 100.00%33.33%50.00%16.67% 29 30 With Interrptible Service (Refectng Actual Physical Interruptions) 31 SE factor (Calculated from line 8)SE2 100.00%33.36%49.96%16.68% 32 SC factor (Calculated from line 7)SC2 100.00%33.47%49.79%16.74% 33 SG factor (line 32'75% + line 31'25%)SG2 100.00%33.45%49.83%16.72% 34 35 36 No Interruptible Service 37 38 Cost of Service 39 Energy Cost SE1 $500,000,000 $166,666,667 $250,000,000 $83,333,333 40 Demand Related Costs SG1 $1,000,000,000 $333,333,333 $500,000,000 $166,666,667 41 Sum of Cost $1,500,000,000 $500,000,000 $750,000,000 $250,000,000 4243~ 44 Special Contract Revenue Situs $20,000,000 $20,000,000 45 Revenues from all other customers Situs $1,480,000,000 $SOO,OOO,OOO $730,000,000 $2SO,000,000 46 47 48 With Interruptible Service & Ancilary Service Contract 49 50 Cost of Service 51 Energy Cost SE1 $498,000,000 $166,000,000 $249,000,000 $83,000,000 52 Demand Related Costs SG1 $998,000,000 $332,666,667 $499,000,000 $166,333,333 53 Ancilary Service Contract. Economic Curtilment (Demand)SG1 $2,000,000 $666,667 $1,000,000 $333,333 54 Ancilary Service Contract - Economic Curtilment (Energy)SE1 $2,000,000 $666,667 $1,000,000 $333,333 55 Sum of Cost $1,500,000,000 $500,000,000 $750,000,000 $250,000,000 56 57 Revenues 58 Special Contract Revenue Situs $20,000,000 $20,000,000 59 Revenues from all other customers Situs $1,480,000,000 $SOO,OOO,OOO $730,000,000 $2SO,000,000 2010 Protocol - Appendix 0 3 Rocky Mountain Power Exhibit No. 1 Page 53 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly APPENDIXE 2011 Klamath Surcharge Situs ECO Hydro Total 2012 Klamath Surcharge Situs ECD Hydro Total 2013 Klamath Surcharge Situs ECD Hydro Total 2014 Klamath Surcharge Situs ECD Hydro Total 2015 Klamath Surcharge Situs ECD Hydro Total 2016 Klamath Surcharge Situs ECD Hydro Total 6 Year NPV 2011-2016 ~ 7.36% . Klamath Surcharge Situs ECD Hydro Total 2010 Protocol- Appendix E 2010 Protocol- Appendix E 6 Year Levelized ECD Hydro Endowment Fixed Dollar Proposal Revenue Requirement ($000) Rocky Mountain Power Exhibit No. 1 Page 54 of 57 Case No. PAC.E-10-09 Witness: Andrea L. Kelly California 1 FERC (70) 60 California Idaho (976) 836 FERC (70) 60 Wyoming (2,955) 484 Total (1 ) (O)!)F.' (1 ) Idaho Wyoming FERC (976) (2,955) (70)836 484 60 ¡~~wl',III""'l~If"'..~1i. California Oregon Washington1 ,062 11,496 (1,286) . / (23l,..J§l (745) ..(2,a3,X"2/; Utah (7,272) 6,240 (i1~~~l:" Total California 1 Utah (7,272) 6,240 Wyoming (2,955) 484 FERC (70) 60 California 1 Oregon 1 Idaho (976) 836 California 1 California Oregon Wyoming (13,932) 2,281 FERC (330) 281 Rocky Mountain Power Exhibit NO.1 Page 55 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly APPENDIXF Rocky Mountain Power Exhibit No. 1 Page 56 of 57 Case No. PAC-E-10-09 Witness: Andrea L. Kelly 2010 Protocol - Appendix F Methodology for Determining Mid-C (MC) Factor Energy for each Mid-C contract is allocated as follows to determine the MC factor. . Priest Rapids energy is assigned 100% to Oregon. . Rocky Reach energy is allocated on the SG factor. . Wanapum energy is assigned to Oregon and Washington based upon each state's respective share of the SG factor. o Wanapum energy assigned to Oregon = Oregon SG / (total Oregon and Washington SG). o Wanapum energy assigned to Washington = Washington SG / (total Oregon and Washington SG). . Wells energy is allocated on the SG factor. . The Grant replacement contracts begin at the time the Priest Rapids contract terminates. The energy from these contracts is assigned to Oregon through October 31, 2009. . Effective November 1, 2009, the date the Wanapum contract expires, the Grant replacement contract energy is divided into two pieces based on PacifiCorp's share of the nameplate of Priest Rapids and Wanapum as shown in the following calculation: Nameplate PacifiCorp's PacifiCorp's Share of PacifCorp's Share of CapacityMW Share- %Nameplate - MW Nameplate - % Priest Rapids 789 13.9%110 41.5% Wanapum 831 18.7%155 58.65% 1,620 265 100.00% · The Priest Rapids portion of the Grant County replacement contracts is 41.35%. The energy associated with the Grant County replacement contracts for Priest Rapids is assigned 100% to Oregon. · The Wanapum portion of the Grant County replacement contracts is 58.65%. The energy associated with the Grant County replacement contracts for Wanapum is assigned to Washington based on the ratio of the Washington SG factor to the sum of the Oregon and Washington SG factors. The remaining energy from the Wanapum portion is assigned to Oregon. After all of the energy from the Mid-Columbia Contracts has been assigned or allocated to each State, then the MC factor is created by dividing each State's energy by the total energy associated with the Mid- Columbia Contracts. The MC factor is used to allocate the Mid-Columbia Contract embedded cost differential to each State. 1 20 1 0 P r o t o c o l - A p p e n d i x F Al l o c a t i o n o f E a c h M i d - C o l u m b i a C o n t r a c t Fa c t o r s U s e d t o A l l o c a t e M i d C E n e r a v t o J u r i s d i c t i o n s Ca l c u l a t i o n o f M i d C F a c t o r /. ... . . . 20 0 5 .2 0 0 5 Pe r c e n t MW h Wa n a p u m Pr i e s t Gr a n t Gr a n t Mi d C Pr i e s t Pri e s t Gr a n t Wa n a p u m G r a n t Pr i e s t R a p i d s Ro c k y R e a c h Re p l a c e m e n t Re p l a c e m e n t MC F a c t o r Co n t r a c t s Ra o i d s 1 1 Ro c k v R e a c h 2 1 W a n a p u m 3 1 We l l s 41 Re p l a c e m e n t 5 1 Re p l a c e m e n t 5 1 11 21 Wa n a p u m 3 1 We l l s 41 51 51 To t a l M i d - C % Ca l i f o m l a 1.8 0 % 1.8 0 % 5, 6 5 8 4,7 4 9 10 , 4 0 7 0. 5 4 % Or e g o n 10 0 . 0 0 % 28 . 8 6 % 76 . 9 4 % 28 . 8 6 % 10 0 . 0 0 % 76 . 9 4 % 56 7 , 5 5 9 90 , 8 2 9 59 6 , 4 9 8 76 , 2 3 8 1, 3 3 1 , 1 2 5 69 . 2 7 % Wa s h i n g t o n 8. 6 5 % 23 . 0 6 % 8. 6 5 % 0. 0 0 % 23 . 0 6 % 27 , 2 2 2 17 8 , 7 7 2 22 , 8 4 9 22 8 , 8 4 2 11 . 9 1 % Ut a h 41 . 9 3 % 41 . 9 3 % 13 1 , 9 8 4 11 0 . 7 8 3 24 2 , 7 6 7 12 . 6 3 % Id a h o 5. 8 5 % 5. 8 5 % 18 , 4 2 6 15 , 4 6 6 33 , 8 9 2 1.7 6 % Wv o m i n o 12 . 9 1 % 12 . 9 1 % 40 , 6 3 6 34 , 1 0 8 74 , 7 4 4 3. 8 9 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 56 7 , 5 5 9 31 4 , 7 5 4 77 5 , 2 7 0 26 4 , 1 9 3 - 1,9 2 1 , 7 7 7 10 0 . 0 0 % 20 0 1 ... . . . 20 0 1 Pe r c e n t MW h Wa n a p u m Pr i e s t G r a n t Gr a n t Mid C Pr i e s t Pr i e s t . Gr a n t Wa n a p u m G r a n t Pr i e s t R a p i d s Ro c k y Re a c h Re p l a c e m e n t Re p l a c e m e n t MC F a c t o r Co n t r a c t s Ra o i d s 1 1 Ro c k v R e a c h 2 1 W a n a o u m 3 1 We l l s 41 Re o l a c e m e n t 5 1 Re o l a c e m a n t 5 1 11 21 Wa n a o u m 3 1 We l l s 41 51 51 To t a l M i d - C % Ca l ~ o m i a 1. 7 3 % 1. 7 3 % 5,5 7 4,5 8 1 10 , 0 3 8 0.5 2 % Or e g o n 10 0 . 0 0 % 27 . 5 6 % 76 . 6 8 % 27 . 5 6 % 10 0 . 0 0 % 76 . 6 8 % 86 , 7 4 6 59 4 , 4 4 4 72 , 8 1 1 56 4 , 6 8 3 1,3 1 8 , 6 8 4 68 . 7 2 % Wa s h i n g t o n 8.3 8 % 23 . 3 2 % 8.3 8 % 0.0 0 % 23 . 3 2 % 26 , 3 8 8 18 0 , 8 2 6 22 . 1 4 9 22 9 , 3 6 3 11 . 9 5 % Uta h 44 . 1 3 % 44 . 1 3 % 13 8 , 8 9 9 11 6 , 5 8 7 25 5 , 4 8 6 13 . 3 1 % Id a h o 5.5 9 % 5.5 9 % 17 , 5 8 2 14 , 7 5 8 32 , 3 4 0 1. 6 9 % Wv o m i n o 12 . 6 1 % 12 . 6 1 % 39 , 6 8 2 33 , 3 0 8 72 , 9 9 0 3.8 0 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 31 4 7 5 4 77 5 , 2 7 0 26 4 1 9 3 56 4 6 8 3 19 1 8 9 0 0 10 0 . 0 0 % 20 1 1 20 1 1 Pe r c e n t MW h Wa n a p u m Pr i e s t G r a n t Gr a n t Mld C Pr i e s t Pr i e s t G r a n t Wa n a p u m G r a n t Pr i e s t R a p i d s Ro c k y R e a c h Re p l a c e m e n t Re p l a c e m e n t MC F a c t o r Co n t r a c t s Ra I d s 1 1 Ro c k v R e a c h 2 1 W a n a o u m 3 1 We l l s 41 Re p l a c e m e n t 5 1 Re p l a c e m e n t 5 1 11 21 Wa n a o u m 3 1 We l l s 41 51 51 To t a l M i d - C % Ca l i f o r n i a 1. 6 5 % 1. 6 5 % 5,2 0 0 4,3 6 5 9,5 6 5 0.6 5 % Or e g o n 10 0 . 0 0 % 26 . 1 3 % 76 . 1 8 % 26 . 1 3 % 10 0 . 0 0 % 76 . 1 8 % 82 , 2 3 1 - 69 , 0 2 1 37 2 , 3 2 7 40 2 , 3 2 5 92 5 , 9 0 4 62 . 5 9 % Wa s h i n g t o n 8.1 7 % 23 . 8 2 % 8.1 7 % 0.0 0 % 23 . 8 2 % 25 , 7 0 8 21 , 5 7 9 - 12 5 , 7 7 6 17 3 , 0 6 4 11 . 7 0 % Uta h 46 . 9 6 % 46 . 9 6 % 14 7 , 8 1 0 12 4 , 0 6 6 27 1 , 8 7 6 .1 8 . 3 8 % Id a h o 5.2 0 % 5.2 0 % 16 , 3 5 3 13 , 7 2 6 30 , 0 7 9 2.0 3 % Wv ö m i n c 11 . 9 0 % 11 . 9 0 % 37 , 4 5 2 31 , 4 3 6 68 , 8 8 7 4.6 6 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 10 0 . 0 0 % 31 4 , 7 5 4 - 26 4 , 1 9 3 37 2 , 3 2 7 52 8 , 1 0 1 1,4 7 9 , 3 7 5 10 0 . 0 0 % (1 ) P r i e s t R a p i d s P o w e r S a l e s A 9 r e e m e n t w i t h G r a n t C o u n t y d a t e d M a y 2 , 1 9 5 6 (2 ) R o c k y R e a c h P o w e r S a l e s A g r e e m e n t w i t h C h e l a n C o u n t y d a t e d N o v e m b e r 1 4 , 1 9 5 7 (3 ) W a n a p u m P o w e r S a l e s A g r e e m e n t w i t h G r a n t C o u n t y d a t e d J u n e 2 2 , 1 9 5 9 (4 ) W e l l s P o w e r S a l e s A 9 r e e m e n t w i t h D o u g l a s C o u n t y d a t e d S e p t e m b e r 1 8 , 1 9 6 3 (5 ) P r i e s t R a p i d s P r o j e c t P r o d u c t S a l e s A g r e e m e n t w i t h G r a n t C o u n t y d a t e d D e c e m b e r 3 1 , 2 0 0 1 Th e A d d i t i o n a l P r o d u c t S a l e s A g r e e m e n t w i t h G r a n t C o u n t y d a t e d D e c e m b e r 3 1 , 2 0 0 1 Th e P r i e s t R a p i d s R e a s o n a b l e P o r t i o n P o w e r S a l e s A g r e e m e n t w i t h G r a n t C o u n t y d a t e d D e c e m b e r 3 1 , 2 0 0 1 20 1 0 P r o t o c o l - A p p e n d i x F 2 :: o m ; o ;: i i ~ 0 16 ( 1 e ' ~ g¡ Z ; : o . .. 0 z š : ~ 1 J 9 g a. ~ . . : : al c ; - 0 i . II m i i : : r~ ~ " l ;; ' ? 0 1 0 (1 o - . : E =( 0 0 g ¡ o. _ ~