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Home My WebLink About20081027Goins Direct.pdfDepartment of Energy Washington, DC 20585 RECEIVED 2068 OCT 21 AM 10: 23 October 24, 2008 IDAHO PUBi¡Ç.. ' UTIUTIES COMMISSION VIA OVERNIGHT SERVICE Ms. Jean Jewell Commission Secretar Idaho Public Utilities Commission 472 W Washington P.O. Box 83720 Boise, il 83720-0074 RE: Case No. IPC-E-08-10 Dear Ms. Jewell: Enclosed please find: (l)an original and 10 copies of the Direct Testimony and Exhibits of Dr. Dennis W. Goins on behalf of the United States Departent of Energy in the above-captioned proceeding; (2) an additional copy of each of these items, that I request be date-stamped and retued in the enclosed postage paid envelope; (3) a disk upon which each of these items is set out in computer searchable form. If you have any questions concerning this filing, please contact me at (202) 586-3409. Sincerely yours,~~ Arur Per Bi1 Attorney for the United States Deparent of Energy Offce of the General Counsel United States Deparent of Eiergy i 000 Independence Avenue SW Washington, D.C. 20585 Arhur.Bruder~hq.doe.gov (202) 586-3409 * Printed with soy ink on recycled paper CERTIFICATE OF SERVICE - IDAHO PUC CASE NO. IPC-E-08-10 I hereby certify that I have, this 24th day of October, 2008, served or caused to be served a tre and correct copy of the attached Testimony and Exhibits of Dr. Dennis W. Goins on behalf of the United States Departent of Energy upon each of the individuals listed below, by: (1) placing the same in the United States Mail, addressed to the street address set out below; (2) electronic transmission ofthe same to the email address set out below; (3) sending an original and ten (10) copies of the same via Federal Express to the Secretary of the Commission. Ms. Jean Jewell, Secretary Idaho Public Utilities Commission 472 W. Washington Boise,ID 83702 jean.jewell~puc.idaho.gov Barton L. Kline Lisa D. Nordstrom Idaho Power Company 1221 W. Idaho St. (83702) P.O. Box 70 Boise, ID 83707-0070 bkline~idahopower.com lnordstrom~idahopower.com JohnR. Gale Vice President, Regulatory Affairs Idaho Power Company 1221 W. Idaho St. (83702) P.O. Box 70 Boise, ID 83707-0070 rgale~idahopower.com; Weldon Stutzman Neil Price Deputy Attorneys General Idaho Public Service Commission 472 W. Washington (83702) PO Box 83720 Boise, ID 83720-0074 weldon.stutzman~puc.idaho.gov neil. price~puc.idaho.gov Peter J. Richardson Richardson & O'Lear 515 N. 27th St. P.O. Box 7218 Boise, il 83702 peter~richardsonandolear C-tF_~o-)Jm:iWo0."9,.3:01 ~3:i- ..(ñn S(t ..-O'~ Nc.Z ~§8-lN.. ;0m('m..mr:: Dr. Don Reading Ben Johnson Associates 6070 Hil Road Boise, il 83703 dreading~mindspring.com Randall C. Budge Eric L. Olsen Racine, Olson, Nye, Budge & Bailey, Charered P.O. Box 1390 20 i E. Center Pocatello, ID 83204-1391 rcb~racinelaw .net elo~racinelaw .net Anthony Yanel 29814 Lake Road Bay Vilage, OH 44140 yankel~attbi.com Michael Kurz, Esq. Kur J. Boehm, Esq. Boehm, Kurz & Lowry 36 E. Seventh Street, Suite 1510 Cincinnati, OH 45202 mkz~BKLlawfirm.com kboehm~ BKLlawfirm.com Conley E. Ward Michael Creamer Givens Pursley LLP 601 W. Bannock Street PO Box 2720 Boise, ID 83701-2720 cew~givenspursley.co Dennis E. Peseau, Ph.D. Utility Resources, Inc. 1500 Liberty Street, Suite 250 Salem, OR 97302 dpcseau~cxcitc.com -2- Brad M. Purdy Attorney at Law 2019 N.l 7thSt. Boise, Idaho 83702 bmpurdy(?hotmail.com Ken Miler Snake River Allance Box 1731 Boise, ID 83701 kmiler(?snakeriverallance.org Kevin Higgins Energy Strategies LLC Parkside Towers 215 South State Street Suite 200 Salt Lake City, UT 84111 khiggins(?energystrat.com Qs rT ~.J Arhur Perry Bru~r, Esq. Office of the General Counsel United States Departent of Energy Washington, DC 20585 (202) 586-3409 -3- ( RECEIVED Arthur Perry Bruder (admitted pro hac vice) 1000 Independence Ave. SW Washington, D.C. 20585 phone: (202) 58603409 FAX: (202) 586-7479 arthu r.bruderßùhq. doe. gov Attorney/Representative for the United States Department of Energy 2088 OCT 27 AM 10=23 IDAHO PUBLIC UTILITIES COMMISSION STATE OF IDAHO BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION CASE NO. IPC-E-08-10 IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPAN FOR AUTHORITY TO INCREASE ITS RATES AN CHAGES FOR ELECTRIC SERVICE TO ELECTRIC CUSTOMERS IN THE STATE OF IDAHO DIRCT TESTIMONY OF DR. DENNIS W. GOINS ON BEHALF OF THE U.S. DEPARTMENT OF ENERGY October 24, 2008 TABLE OF CONTENTS Page INTRODUCTION AND QUALIFICATIONS..............................................................................1 CONCLUSIONS.....................................................................................................................3 RECOMMENDATIONS ........................................................................................................... 7 COST OF SERVICE ............................................................................................................. 11 REVENUE SPREAD ............................................................................................................ 22 EXHIBITS APPENDIX Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page i 2 Q. 3 4 A. 5 6 7 Q. 8 9 A. 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 INRODUCTION AN QUALIFICATIONS PLEASE STATE YOUR NAM, OCCUPATION, AN BUSINESS ADDRESS. My name is Dennis W. Goins. I operate Potomac Management Group, an economic and management consulting firm. My business address is 5801 Westchester Street, Alexandria, Virginia 22310. PLEASE DESCRIBE YOUR EDUCATIONAL AN PROFESSIONAL BACKGROUN. I received a Ph.D. degree in economics and a Master of Economics degree from North Carolina State University. I also earned a B.A. degree with honors in economics from Wake Forest University. From 1974 through 1977 I worked as a staff economist at the North Carolina Utilties Commission (NCUC). During my tenure at the NCUC, I testified in numerous cases involving electric, gas, and telephone utilities on such issues as cost of service, rate design, intercorporate transactions, and load forecasting. While at the NCUC, I also served as a member of the Ratemaking Task Force in the national Electric Utilty Rate Design Study sponsored by the Electric Power Research Institute (EPRI) and the National Association of Regulatory Utility Commissioners (NARUC). Since 1978 I have worked as an economic and management consultant to firms and organizations in the private and public sectors. My assignments focus primarily on market structure, policy, planning, and pricing issues involving firms that operate in energy markets. For example, I have conducted detailed analyses of product pricing, cost of service, rate design, and interutilty planning, operations, and pricing; prepared analyses related to utilty mergers, transmission access and pricing, and the emergence of competitive markets; evaluated and developed Case No. IPC-E-08-10 Dennis W. Goins - DOE-Di Page 1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Q. 22 A. 23 24 25 regulatory incentive mechanisms applicable to utilty operations; and assisted clients in analyzing and negotiating interchange agreements and power and fuel supply contracts. I have also assisted clients on electric power market restructuring issues in Arkansas, New Jersey, New York, South Carolina, Texas, and Virginia. I have submitted testimony and affdavits and provided technical assistance in more than 100 proceedings before state and federal agencies as an expert in competitive market issues, regulatory policy, utility planning and operating practices, cost of service, and rate design. These agencies include the Federal Energy Regulatory Commission (FERC), the Government Accountability Offce, the First Judicial District Court of Montana, the Circuit Court of Kanawha County, West Virginia, and regulatory agencies in Alabama, Arizona, Arkansas, Colorado, Florida, Georgia, Idaho, Ilinois, Kentucky, Louisiana, Maine, Marland, Massachusetts, Minnesota, Mississippi, New Jersey, New York, North Carolina, Ohio, Oklahoma, South Carolina, Texas, Utah, Vermont, Virginia, and the District of Columbia. Additional details of my educational and professional background are presented in the Appendix. I have also participated in several cases before this Commission involving Idaho Power Company (IPC). These cases include Docket Nos. IPC-E-03-13, IPC-E-04-23, IPC-E-05-28, and IPC-E-07-08. ON WHOSE BEHAF AR YOU TESTIFYING IN TilS PROCEEDING? I am testifying on behalf of the U.S. Deparment of Energy (DOE) representing the Federal Executive Agencies (FEA), which is comprised of all Federal facilities served by Idaho Power Company (IPC). Two of the larger FEA facilities are the Deparment of Energy's Idaho National Laboratory (DOE) and Mountain Home Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 2 1 2 3 Q. 4 5 A. 6 7 8 9 10 Q. 11 12 A. 13 14 15 16 17 Q. 18 A. 19 20 21 22 23 '" Air Force Base. IPC serves DOE under a special contract, and serves the bulk of Mountain Home AFB' s load under Schedule 19 Large Power Service. WHT ASSIGNMNT WERE YOU GIVEN WHEN YOU WERE RETAIED? I was asked to undertake two primary tasks: 1. Review IPC's proposed cost-of-service analyses (including pro forma adjustments) and related rates. 2. Identify any major deficiencies in the cost analyses and proposed rates and suggest recommended changes. WHT SPECIFIC INORMTION DID YOU REVIEW IN CONDUCTING YOUR EVALUATION? I reviewed IPC's application, testimony, exhibits, and responses to requests for' information related to cost of service, revenue spread, and rate design issues. I also reviewed documents found on web sites operated by the Commission and by IPC. CONCLUSIONS WHAT CONCLUSIONS HAVE YOU REACHED? On the basis of my review and evaluation, I have concluded the following: .1. IPC's Cost of Service. IPC has proposed increasing base revenues by approximately $66.6 milion (9.89 percent). In developing proposed rates for its retail electric services, IPC first conducted three (3) cost-of-servIce (COS) studies for the test year ending December 31, 2008. In these cost analyses, IPC allocated and/or directly assigned its costs to functional Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 3 1 2 3 segments of its retail electric business. The return component of IPC's costs reflects a requested 8.55 percent return on its retail jurisdictional rate base (using an 11.25 percent return on common equity). IPC calls the three cost studies the:4 5 6 7 8 9 10 11 . Base Case, which is supposedly similar to the COS methodology IPC presented in Case No. IPC-E-03-13. In the Base Case, IPC classified 59.38 percent of its fixed costs associated with steam (FERC accounts 310-316) and hydro (FERC accounts 330-336) production plant as energy-related costs, and the remainder-40.62 percent-as demand- related costs. The 59.38 percent classification is equal to the IPC jurisdictional load factor. IPC allocated its demand-related production costs to customer classes using a marginal-cost-weighted average of each class' contribution to IPC's 12 monthly coincident peaks. That is, IPC used a version of the weighted 12CP (WI2CP) allocation method. In its final order in Case No. IPC-E-03-13, the Commission found that the W12CP methodology reflected a reasonable approximation of class cost responsibilty. . Modified Base Case, which is the Base Case with two modifications. First, IPC classified purchased power expenses (FERC account 555Y as demand and energy costs in the same manner as hydro and steam production plant costs are classified-that is, 40.62 percent as demand-related costs and 59.38 percent as energy-related costs. (In the Base Case, IPC classified almost all of its purchased power costs as energy-related costs.) Second, energy cost allocators E 1 OS and 12 13 14 15 16 17 18 19 20 21 22 23 24 1 This account include sub-accounts 555.1 (power purchases) and 555.2 (purchases from cogeneration and small power producers-or CSPPs). Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 4 1 2 EI0NS were derived using the average of each class' normalized kWh sales and its marginal-cost-weighted normalized kWh sales. 3 . 3CP/12CP, which is the Modified Base Case with production plant split into two categories that I call baseload capacitf and peaking capacity. IPC assigned all steam (FERC accounts 310-316) and hydro (pERC accounts 330-336) production plant to the baseload capacity category, and combustion turbine (CT) plant costs (FERC accounts 340-346) to the peaking capacity category. IPC allocated plant costs assigned as peaking capacity on the basis of each class' average coincident peak in June, July, and August (that is, a 3CP allocation method). Like the Modified Base Case, hydro and steam production plant costs were allocated using a 12CP allocator. However, the allocation factors were not weighted by IPC's marginal-costs-that is, IPC used an unweighted 12CP allocator. IPC's preferred cost-of-service methodology is the 3CP/12CP method. According to IPC, the 3CPI12CP method best reflects factors driving IPC's need for capacity to meet growing summer demands as well as year- round demands. 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 2. Cost-of-Service Problems. In this case, IPC recommends a production cost allocation method that the Commission has never approved. Prior to this case, the Commission's last addressed the allocation of demand- related production costs in Case No. IPC-E-03-13, in which it approved the W12CP method-a method that the Commission had endorsed in several preceding cases. In the current case, IPC recommends a seriously 2 Includes capacity designed to serve both baseload and intermediate load requirements. Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 5 1 2 flawed 3CPI12CP allocation method. In particular, the IPC's 3CPI12CP cost-of-service study (COSS): 5 . Departs from Commission precedent. . Improperly classifies steam and hydro production plant costs and Account 555 purchased power expenses as demand- and energy- related costs. 3 4 6 8 . Improperly splits Account 555 costs into base load and peaking categories. I discuss this in more detail. later. . Fails to track costs accurately. For example, IPC's 3CPI12CP cost study does not reflect the concentration of purchased power costs in the summer peak months, thereby understating costs assigned to summer peak usage. That is, costs that should be allocated primarily to classes with heavy summer electricity usage are instead allocated to classes with high load factor usage in non-summer, off-peak months (for example, special contract and Schedule 19 customers). As a result, low load factor classes with high summer demands are able to avoid responsibility for a large share of purchased power costs they cause IPC to incur. 7 9 10 11 12 13 14 15 16 17 18 24 . Fails to allocate steam and hydro production plant costs; fuel costs, and revenues from off-system sales (Account 447) in a manner that properly aligns class cost responsibilty with class loads that underlie these costs and revenues. For example, most of IPC's off-system sales revenue is produced in non-summer, non-peak months when significant excess baseload capacity (steam and hydro capacity) is available. Higher load factor classes are allocated most ofIPC's 19 20 21 22 23 25 Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 6 2 3 4 5 6 7 3. 8 9 10 11 12 13 14 15 16 17 18 19 base load production costs, and therefore should also be allocated most of its off-system sales revenues. Yet IPC allocates off-system sales revenue on the basis of marginal-cost-weighted energy usage. As a result, lower load factor classes with heavy energy usage in peak months are allocated too large a share of off-system sales revenues- thereby understating their test-year cost responsibility. Revenue Spread. IPC spread its proposed revenue increase among rate classes using the following 4-step sequential approach: . Identify sales revenue increases (or decreases) necessar to match total revenue from each class with IPC's estimated cost of serving the class as determined in IPC's 3CP/12CP cost study. . Set a IS-percent limit on rate increases to Special Contracts customers and Schedules 19 Large Power Service, 24 Irrigation Service, and 42 Traffc Control Lighting. . Hold revenues from Schedules 15,40, and 41 at test-year levels under present rates instead of decreasing revenues as indicated by the COSS results-that is, give no initial increase to this class. . Spread the revenue shortfall caused by the IS-percent cap on class increases across all non-capped rate schedules. RECOMMNDATIONS WHT DO YOU RECOMMEND ON THE BASIS OF THESE 20 21 Q. 22 CONCLUSIONS? 23 A.I recommend the following: Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 7 1. 2 3 4 2. 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Reject IPC's 3CP/12CP cost-of-service study.3 The study is seriously and probably fatally flawed because it fails to align cost allocation with cost responsibilty . Reject IPC's classification of steam and hydro production plant costs as demand- and energy-related costs. Instead, all steam and hydro production plant costs should be classified as demand-related costs. IPC's proposed classification scheme suffers from at least two arbitrary assumptions. First, the classification scheme arbitrarily assumes that IPC's system load factor somehow identifies the portion of generation plant costs that is supposedly energy-related. IPC has provided no empirical analysis to justify or support its choice of system load factor to classify production plant costs.4 Second, like most capital substitution arguments,S the classification scheme implicitly assumes that if all production plant costs were classified as demand-related costs, higher load factor customers would receive a disproportionate share of the cheap energy benefits of base load and intermediate capacity without paying a proportionate share of the higher capital costs of such capacity-particularly if demand-related capacity costs are allocated on the basis of peak demands. Neither assumption is intuitively obvious or empirically supportable. 3 Throughout my testimony I focus on IPC's 3CP/12CP cost study since IPC recommends this study. However, IPC's Base Case and Modified Base Case cost studies suffer from deficiencies comparable to those I describe regarding the 3CPI12CP cost study. As a result, neither the Base Case nor the Modified Base Case studies should be used for setting IPC's rates in this case.4 IPC witness Timothy Tatum (direct testimony at 29:7-10) says that the load factor methodology used to classify steam and hydro production plant reflects "the methodology preferred by the Commission in prior general rate proceedings."S With respect to system planning analyses that focus on choosing a mix of generation plant that meets expected demand at least cost, capital substitution refers generally to trade-offs between production plant with relatively high capital costs but low energy costs (for example, baseload generating units) and production plant with relatively low capital costs but high energy costs (for example, combustion turbines). Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 8 1 2 3 3. If the Commission allows IPC to classify steam and hydro plant costs into demand and energy cost components, then system load factor should not be used to determine the energy cost component. Instead, as an alternative, I recommend classifying 57.10 percent of these plant costs as demand and 42.90 percent as energy. (I describe how these percentages are derived later in my testimony.) With respect to the classification of hydro plant, IPC uses hydro plant not only to meet baseload demands, but also to serve peak loads. This operating flexibility is not reflected in a classification scheme based on system load factor. 4 5 6 7 8 9 10 4. Reject IPC's classification of Account 555 purchased power costs. Instead, they should be classified using the same alternative classification scheme I propose for classifying steam and hydro plant costs (that is, 57.10 percent demand and 42.90 percent energy.) 11 12 13 14 5. Reject IPC's proposed assignent of all demand-related hydro plant costs to the base load capacity category. This assignment ignores the role that hydro plant plays in meeting IPC's summer peak demands. Instead, I recommend assigning 50 percent of demand-related hydro costs to the baseload plant category (which is allocated on the basis of 12CP demands) and 50 percent to the peaking category (which is allocated on the basis of 3CP demands). My recommended alternative classification scheme falls between the 100-percent demand classification scheme IPC uses for peaking CTs and the approximately 40 percent demand/60 percent energy scheme it uses to classify baseload steam generating costs.6 15 16 17 18 19 20 21 22 23 6 A reasonable argument could also be made that under IPC's 3CPIl2CP methodology, some portion of steam production plant should be designated as peaking capacity and allocated on the basis of 3CP demands. I do not address this issue in my direct testimony. Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 9 7 6. Reject IPC's proposed assignment of demand-related purchased power costs to baseload and peaking capacity categories on the basis of how it assigns production plant to these categories. IPC's approach assigns far too little of Account 555 costs to the peaking category. Instead, I recommend using the same 50/50 demand and energy split for demand- related Account 555 costs that I recommend for assigning demand",related hydro plant costs. 1 2 3 4 5 6 8 9 10 11 7 Reject IPC's marginal-cost-weighted allocation of energy costs in its 3CP/12CP study. Instead, an unweighted energy cost allocation should be used to ensure that higher load factor classes are assigned a higher percentage of the lower fuel costs associated with baseload capacity. 12 13 14 8. Require IPC to allocate demand-related production costs using a weighted 12CP method. I present results from two W12CP co~t studies that I perfonned in Exhibit Nos. 610 and 611. 22 9. Reject IPC's proposed revenue spread, which is based on its 3CP/12CP cost study results. Instead, I recommend that results from my Exhibit No. 611 be used as a starting point in developing a revenue spread for any rate change the Commission approves in this case. At this point, I have not developed a proposed revenue spread for all classes based on results from my W12CP cost study. However, results from my W12CP cost study- combined with the total unreliability of results from IPC' s costs studies- support an across-the-board revenue spread. Moreover, in addition to my recommended W12CP cost study, other studies that I prepared clearly show that IPC's proposed 15 percent increases for DOE and Schedule 19 are excessive. IPC's proposed increases for these customers are about 1.5 15 16 17 18 19 20 21 23 24 25 Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 10 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 Q. 18 19 A. 20 21 22 23 24 times the system average increase of 9.89 percent. My analyses indicate that increases to DOE and Schedule 19 should be limited to the system average increase and under no circumstance should exceed 1.10 times the system average increase. 10. Require IPC to retain the services of a reputable outside firm to examine, evaluate, and recommend necessary changes to its cost-of-service modeL. More than 5 years have passed since the Commission ordered IPC in Case No. IPC-E-03-13 to work with stakeholders to address cost-of-service issues. The issues have not been resolved. Large customers such as DOE and Mountain Home AFB no longer have confidence that IPC's cost studies properly reflect class cost responsibilty. While my recommended changes mitigate some of the more obvious problems in IPC's cost analyses, they do not resolve a fundamental problem. Specifically, classes driving the need for additional capacity to meet summer peak demands are not being assigned a fair share of the costs of meeting those demands. COST OF SERVICE DID IPC ESTIMATE ITS COST OF SERVIG DIFFERENT CUSTOMER CLASSES? Yes. IPC conducted three detailed cost-of-service studies using data (adjusted in many cases) for the test year ending December 31, 2008. In these cost analyses, IPC classified and then allocated and/or directly assigned its costs to functional segments of its retail electric business. The return component of IPC's costs reflects a requested 8.55 percent return on its Idaho retail jurisdictional rate base (using an 11.25 percent return on common equity). Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 11 Q. 2 A. 3 4 5 6 Q. 7 8 A. 9 10 11 12 Q. 13 14 A. 15 16 17 18 19 20 Q. 21 A. 22 23 DOES YOUR TESTIMONY ADDRESS EACH OF IPC'S COST STUDIES? No. My testimony focuses on IPC's preferred 3CP/12CP cost-of-service study. However, most of my criticisms of IPC's 3CPI12CP cost study would also be applicable to IPC's Base Case and Modified Base Case cost studies that I described earlier. HAS THE COMMISSION EVER APPROVED IPC'S 3CP/12CP METHOD FOR ALLOCATIG DEMA-RELATED PRODUCTION COSTS? No. Prior to this case, the Commission's last addressed the allocation of demand- related production costs in Case No. IPC-E-03-13, in which it approved the W12CP method-a method that the Commission had also endorsed in several preceding cases. IN ITS 3CPI12CP COST STUDY, HOW DID IPC ALLOCATE DEMAD- RELATED PRODUCTION AN PURCHASED POWER COSTS? In its 3CP/12CP cost study, IPC allocated demand-related steam and hydro production plant and Account 555 purchased power costs categorized as baseload capacity on the basis of each class' unweighted 12 monthly coincident peak demands (12CP). IPC allocated demand-related CT plant and purchased power costs categorized as peaking capacity on the basis of each class' unweighted monthly coincident peak demands in the 3 summer months June-August (3CP). HOW DID IPC ALLOCATE ENERGY-RELATED COSTS? In its 3CP/12CP cost study, IPC used the average of marginal-cost-weighted and unweighted summer and non-summer ratios to derive the summer and non- summer energy allocation factors (EI0S and EI0NS). Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 12 Q. 2 3 A. 4 5 6 7 8 9 10 Q. 11 12 A. 13 14 15 16 17 18 19 20 21 22 23 PLEASE DESCRIE HOW IPC CLASSIFIED PRODUCTION PLANT AND PURCHASED POWER COSTS. In its 3CP/12CP cost study,7 IPC classified steam (FERC Accounts 310-316) and hydro (FERC Accounts 330-336) production plant costs and purchased power costs (FERC Account 555) as demand- and energy-related costs. IPC set the energy-related component of these costs equal to the Idaho jurisdictional load factor (59.38 percent), with the residual-40.62 percent or (1 - load factor)- classified as demand-related costs. IPC classified 100 percent of its investment in combustion turbines (FERC Accounts 340-346) as demand related costs. DO YOU AGREE WITH IPC'S CLASSIFICATION OF PRODUCTION PLANT AN PURCHASED POWER COSTS? I agree with the classification of CT costs, but disagree with IPC' classification of steam and hydro production plant costs and purchased power expenses. For example, according to the NARUC cost allocation manual and contrar to IPC's classification, all hydro plant costs and most hydro operation and maintenance expenses should be classified as demand-related costs.8 In general, IPC's classification of steam and hydro production plant and purchased power costs rests on questionable assumptions, the validity of which is neither intuitively obvious nor empirically demonstrable. More specifically, IPC's steam and hydro classification scheme rests on the following arbitrary assumptions: 1. Higher load factor customers receive a disproportionate share of the cheaper energy benefits of baseload and intermediate capacity without paying a proportionate share of the higher capital costs of such capacity- 7 ¡PC also used the same classification scheme in its Base Case and Modifed Base Case cost studies. 8 National Association of Regulatory Utility Commissioners, Electric Utility Cost Allocation Manual, Washington, DC, January 1992, at 35-38. (NARUC cost manual) Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 13 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Q. 22 23 24 A. 25 paricularly if demand-related capacity costs are allocated on the basis of peak demands. 2. System load factor somehow identifies the portion of generation plant costs that are supposedly energy-related costs. Regarding the first assumption, base load and intermediate plants are planned and designed to operate during more than peak demand periods, and higher load factor customers use energy from such plants in non-peak periods. However, whether higher load factor customers benefit disproportionately from cheaper baseload and intermediate plant energy is an empirical question that IPC has not addressed in this case. Moreover, in addressing this question, the method used to allocate energy-related costs must be considered. For example, if production plant costs are classified as energy-related costs and energy costs are allocated on the basis of average energy use, then low load factor customers will likely receive the benefits of cheaper baseload and intermediate energy without paying a fair share of the capital costs for these plants. Regarding the second assumption, using IPC's system load factor to identify the portion of production plant costs to classify as energy-related costs is totally arbitrary. System load factor is an indicator of the relative use of supply resources (production plant) over time, and provides neither an economic nor engineering rationale for classifying production plant costs. IF THE COMMISSION REQUIRS THT SOME PART OF STEAM AN HYDRO PLANT COSTS BE CLASSIFIED AS ENERGY COSTS, HOW SHOULD THE ENERGY-RELATED COMPONENT BE IDENTIFIED? Let me reiterate-in my opinion, all production plant costs should be classified as demand-related costs. Nonetheless, if part ofIPC's production plant costs is Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 14 1 2 3 4 5 6 7 Q. 8 A. 9 10 11 12 13 14 15 16 17 18 19 Q. 20 21 22 A. 23 24 25 classified as energy-related costs, I recommend setting the percentage of such plant costs classified as energy-related costs equal to the ratio of IPC's weighted energy allocators in non-capacity deficit months-that is, all months other than May - September and December-to the weighted 12-month allocator. This approach provides at least some intuitive linkage between the energy cost of production plant and high load factor energy use. WHAT is THE RESULT OF USING TilS APPROACH? Under this approach, 42.90 percent of IPC's steam and hydro production plant Costs would be classified as energy-related costs. This percentage is derived as follows: . In IPC',s Exhibit No. 59, page 5, sum the weighted retail jurisdiction energy factors for the six non-capacity deficit months-that is, all months other than May - September and December. This value is 468,444,966. . Divide 468,444,966 by 1,092,008,268-the sum of weighted retail jurisdiction energy use for all 12 months. The resulting value is 42.90 percent. The remaining 57.10 percent of costs should be classified as demand. DOES THIS ALTERNATIVE CLASSIFICATION SCHEME BETTER REFLECT DRIVERS UNERLYING IPC'S NEED FOR STEAM AN HYRO PRODUCTION PLANT? Yes. As I noted earlier, steam and hydro generation plant investments are primarily undertaken to meet demand, and a classification scheme that results in allocating nearly 60 percent of these costs on the basis of energy simply makes no economic or engineering sense. This problem is paricularly acute for hydro plant. Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 15 2 3 4 5 6 7 8 9 10 Q. 11 12 A. 13 14 15 16 17 18 Q. 19 20 A. 21 22 23 IPC has publicly stated that it often manages its hydro plant to serve peak hours- not simply to meet baseload demand.9 This operating flexibility is not reflected in a classification scheme based on system load factor. My recommended alternative demand-energy classification scheme is reasonable because it recognizes why IPC adds capacity and how it uses that capacity. Moreover, my alternative classification yields logical results that happen to fall between the 100-percent demand classification scheme IPC uses for peaking CTs and the approximately 40 percent demand/60 percent energy scheme it uses to classify baseload steam generating costs. SHOULD YOUR ALTERNATIVE CLASSIFICATION SCHEME ALSO APPLY TO IPC'S PURCHASED POWER COSTS? Yes. In this case, IPC finally recognized that its purchased power costs have a significant demand-related component. However, IPC used its system load factor method to classify Account 555 costs as demand- and energy-related costs. I disagree with this method, and recommend that my alternative method be used to classify purchased power costs. As a result, 57.10 percent of Account 555 costs should be classified as demand, and 42.90 percent should be classified as energy. DID IPC ASSIGN AN HYRO PLANT COSTS TO TH PEAKG CAPACIT CATEGORY? No. IPC assigned all demand-related hydro plant costs to the baseload capacity category. This assignment ignores hydro's role in meeting IPC's summer peak demands and understates cost-responsibilty for summer peak usage. To address this problem, I recommend assigning 50 percent of demand-related hydro costs to 9 For example, see the direct testimony of IPC's witness Timothy Tatum in Docket No. E-07-08 at 12:24- 25. In his testimony in the current case, witness Tatum inexplicably omits any reference to hydro as a peaking resource. See the direct testimony of witness Tatum at 24:4-7. Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 16 1 2 3 4 Q. 5 6 A. 7 8 9 10 11 12 13 14 Q. 15 16 17 A. 18 19 20 21 Q. 22 23 A. 24 25 the baseload plant category (which is allocated on the basis of 12CP demands) and 50 percent to the peaking category (which is allocated on the basis of 3CP demands). DID IPC PROPERLY SPLIT PURCHASED POWER COSTS INTO BASELOAD AN PEAKIG CAPACITY CATEGORIS? No. IPC assigned demand-related purchased power costs to base load and peaking capacity categories on the basis of how it assigns production plant to these categories. This approach ignores the simple fact that nearly half of IPC's Account 555 purchases occur in the summer peak months June-August. IPC's approach assigns far too little of Account 555 costs to the peaking category. Instead, I recommend using the same 50/50 demand and energy split for demand- related Account 555 costs that I recommend for assigning demand-related hydro plant costs. WOULD YOUR RECOMMNDED CHAGES SIGNIFICANTLY AFFECT HOW IPC'S PRODUCTION AN PURCHASED POWER COSTS WERE ALLOCATED TO CUSTOMER CLASSES? Yes. Exhibit No. 607 summarizes these differences. As shown in this exhibit, my recommended changes would justifiably reduce the portion of production plant and purchased power costs classified as energy and shift more costs to the peaking category. HAVE YOU PERFORMD A COST STUDY THAT INCORPORATES YOUR RECOMMNDED CHAGES? Yes. I modified IPC's 3CPI12CP cost study to reflect the recommended changes shown in Exhibit No. 607. In general, results from this study indicate significantly lower cost responsibilties for Schedule 19 and special contract Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 17 2 .3 4 5 6 Q. 7 8 9 A. 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 customers. (See Exhibit No. 608.) For example, my analysis indicates that a 15.71 percent revenue increase (about $916,000) is required to bring DOE to cost of service. In contrast, IPC's 3CP/12CP analysis (Exhibit No. 66) indicates that a 25.37 percent increase ($1.48 milion) is required. This huge disparity shows why properly classifying IPC's hydro plant costs and purchased power costs is criticaL. WH AR YOU CONCERNED SINCE IPC'S PROPOSED INCREASE FOR DOE-15 PERCENT-IS ALMOST IDENTICAL TO THE INCREASE SUGGESTED BY YOUR MODIFIED 3CP/12CP ANALYSIS? My concern is that even with the changes I have discussed, IPC's 3CP/12CP cost study stil significantly overstates cost responsibilty for higher load factor customers. My recommended changes mitigate-but do not fix-fundamental flaws in IPC's 3CP/12CP cost study. For example, in addition to the problems I have cited, IPC's costing approach . Double counts average demands by combining a 3CP and 12CP . allocation approach for demand-related production costs. IPC's 3CPI12CP methodology is similar to peak and average allocation methods described in the NARUC cost manuaL. In typical peak and average cost studies, all demand-related production costs are allocated on the basis of a single measure of peak demand (for example, a single CP or a single measure of several CPs). However, in IPC's 3CPI12CP cost study, IPC has allocated only production costs assigned to the peaking category on the basis of the 3CP demands that are driving IPC's need for capacity. The bulk of demand-related production costs are allocated across all peak and non-peak months on Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 18 1 the basis of 12 CPs, thereby diluting the influence of the principal system peaks that drive the need for capacity. Moreover, IPC's allocation of capacity cost responsibilty is further diluted by classifying almost 60 percent of its fixed production plant costs as energy. The end result of this convoluted process is an assignment of production costs that has no relationship to why and how IPC incurs costs to serve peak demands. . Fails to reflect the concentration of purchased power costs in the summer peak months, thereby understating costs assigned to summer peak usage. As a result, costs that should be allocated to lower load factor classes with heavy summer usage are instead allocated to higher load factor classes (for example, special contract and Schedule 19 customers). Even my recommended 50/50 split of Account 555 costs into baseload and peaking capacity categories is only an indirect correction for this problem. Moreover, the impact of my proposed modification is muted because nearly 43 percent of purchased power costs are allocated on annual energy in my analysis, resulting in a likely understatement of purchased power costs that should be assigned to the summer peaking period. . Fails to align cost responsibilty with the allocation of steam and hydro production plant costs; fuel costs, and revenues from off-system sales (Account 447). I discussed this problem earlier regarding the allocation of off-system sales revenue. A similar problem exists with the allocation of fuel costs under IPC's 3CP/12CP methodology. For example, higher load factor classes are allocated a higher percentage 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 19 1 2 3 Q. 4 5 A. 6 7 8 9 10 11 12 13 14 Q. 15 A. 16 17 18 19 20 21 22 23 24 of fixed production costs without . being allocated a similar higher , percentage of the fuel-cost savings associated with these plants. HAVE YOU ANALYZED HOW THESE FLAWS AFFECT THE ALLOCATION OF COSTS? Yes. I ran IPC's 3CP/12CP cost study again, but made only one change. Instead of assigning production costs to peaking and baseload categories, I simply allocated all demand-related production costs on the basis of a 3CP allocator. I used IPC's classification scheme to identify demand- and energy-related production and purchased power costs. This approach is consistent with a tyical peak and average cost study. 10 The results were dramatic for selected customers compared to IPC's 3CP/12CP study. (See Exhibit No. 609.) For example, the required rate increases for DOE and Schedule 19 fell to 10.82 percent and 11.40 percent, respectively, compared to 25.37 percent and 15.87 percent in IPC's'study. DID YOU PERFORM A WEIGHTED 12CP COST STUY? Yes. Since the W12CP demand-related cost allocation methodology is the last methodology formally approved by the Commission, I decided to conduct a W12CP cost analysis. In my W12CP analysis, I used marginal-cost-weighted loads to allocate demand-related production and transmission costs, and marginal- cost-weighted energy to allocate energy-related costs. I developed this factor without averaging weighted and unweighted loads and energy as IPC did in its Base Case study. I ran two versions of the W12CP modeL. In the first version, I used IPC's load factor method to identify demand- and energy-related fixed production costs. Results from this study indicate that rate increases for Schedule 19 and DOE should be around 11.75 percent-far below results shown in IPC's 10 I am not recommending a peak and average allocation method. I present this peak and average analysis Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 20 2 3 4 5 6 7 Q. 8 A. 9 10 11 12 13 14 15 16 17 18 Q. 19 20 21 A. 22 23 24 3CP/12CP cost study and well below the 15 percent capped increase that IPC recommends. (See Exhibit No. 610.) Results from the second version included my recommended alternative method for identifying demand- and energy-related fixed production costs. Results from this second study indicate that rate increases for Schedule 19 and DOE should be below 8 percent-less than IPC's proposed system average increase. (See Exhibit No. 611.) is IPC'S 3CP/12CP METHODOLOGY REASONABLE? No. In my direct testimony in IPC's 2007 rate case (Case No. IPC-E-07-08), I noted that although the methodology is not widely used, it appeared to be reasonable, even though I preferred allocation methods that were more straightforward. However, in this case, after examining IPC's 3CPI12CP cost methodology and underlying costs more closely, I have concluded that IPC's 3CP/12CP COSS is seriously and probably fatally flawed. The 3CPI12CP methodology as applied by IPC simply does not track cost of service, resulting in too few costs assigned to summer peak months and too many costs assigned to higher load factor customers. As a result, its results should not be relied on to determine class revenue increases. SHOULD THE COMMSSION REQUIR IPC TO ADDRESS PROBLEMS WITH ITS COST ANALYSES NOW INSTEAD OF WAITING FOR FUTUR CASES? Yes. Stakeholders have waited more than 5 years since the Commission ordered IPC to work with stakeholders to address cost-of-service issues. The issues have not been resolved. Large customers such as DOE and Mountain Home AFB no longer have confidence that IPC's cost studies properly reflect class cost only to highlight the serious problems in IPC's 3CP/12CP cost study. Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 21 2 3 4 5 6 7 8 9 10 11 Q. 12 13 A. 14 15 16 Q. 17 A. 18 19 20 21 22 23 24 25 responsibilty. While my recommended changes mitigate some of the more obvious problems with IPC's cost analyses, they do not resolve a fundamental problem. Specifically, classes driving the need for additional capacity to meet summer peak demands are not being assigned a fair share of the costs of meeting those demands. As a result, I recommend that the Commission require IPC to retain the services of a reputable outside firm to examine, evaluate, and recommend necessary changes to its cost-of-service modeL. Interested stakeholders should be allowed to participate in this process, or at least be regularly briefed on IPC's progress in improving its costing analyses. REVENUE SPREAD HOW DID IPC SPREAD ITS PROPOSED REVENU INCREASE AMONG CUSTOMER CLASSES? As I described earlier, IPC used a 4-step sequential approach to spread its proposed revenue increase among rate classes. This approach-which is linked to results from IPC's 3CPI12CP cost study-is presented in IPC Exhibit No. 70. DO YOU AGREE WITH IPC'S PROPOSED REVENUE SPREAD? No. As Ijust noted, correcting some of the obvious flaws in IPC's never-before- approved 3CP/12CP cost study significantly alters the class cost responsibilities on which IPC based its proposed revenue spread. I do not consider results from any ofIPC's cost studies reliable, and do not believe they should be used to spread any revenue increase that IPC receives in this case. As a result, an across-the- board increase for all classes would be reasonable. If the Commission wants to use results from a cost study as a staring point in spreading any revenue increase that IPC receives, then I recommend using results from my W12CP study shown in Exhibit No. 611. If the Commission rejects an across-the-board revenue Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 22 1 spread, I recommend that any increase applied to Schedule 19 and DOE be limited 2 to the system average increase, and under no circumstances should they be more 3 than 1.10 times the system average increase. I base this recommendation on 4 results from my cost analyses. 5 Q.DOES TilS COMPLETE YOUR DIRECT TESTIMONY? 6 A.Yes. Case No. IPC-E-08-10 Dennis W. Goins - DOE - Di Page 23 RECEIVED 208 OCT 27 AM 10: 24 'DAU'J PlJBUC UTILITIES COMMISSION STATE OF IDAHO BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION CASE NO. IPC-E-08-10 IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPAN FOR AUTHORITY TO INCREASE ITS RATES AN CHAGES FOR ELECTRIC SERVICE TO ELECTRIC CUSTOMERS IN TH STATE OF IDAHO EXHffITS TO THE DIRCT TESTIMONY OF DR. DENNS W. GOINS ON BEHAF OF THE U.S. DEPARTMENT OF ENERGY October 24, 2008 STATE OF IDAHO BEFORE TH IDAHO PUBLIC UTILITIES COMMSSION CASE NO. IPC-E-08-10 IN TH MATTER OF THE APPLICATION OF IDAHO POWER COMPAN FOR AUTHORITY TO INCREASE ITS RATES AN CHAGES FOR ELECTRC SERVICE TO ELECTRIC CUSTOMERS IN THE STATE OF IDAHO EXHBIT NO. 607 OF DR. DENNIS W. GOINS ON BEHALF OF THE U.S. DEPARTMENT OF ENERGY October 24, 2008 Al t e r n a t i v e C l a s s i f i c a t i o n o f P r o d u c t i o n F u n c t i o n C o s t s : 3 C P / 1 2 C P De m a n d ( % ) Ba s e / I n t e r m e d i a t e Pe a k i n g En e r g y ( % ) Co s t I t e m IP C DO E IP C DO E IP C DO E Hy d r o P l a n t ( 3 3 0 - 3 3 6 ) 1 40 . 6 2 28 . 5 5 0. 0 0 28 . 5 5 59 . 3 8 42 . 9 0 Pu r c h a s e d P o w e r ( 5 5 5 . 1 ) 31 . 9 5 28 . 5 5 8. 6 7 28 . 5 5 59 . 3 8 42 . 9 0 CS P P ( 5 5 5 . 2 ) 31 . 9 5 28 . 5 5 8. 6 7 28 . 5 5 59 . 3 8 42 . 9 0 CT s / O t h e r ( 3 4 0 - 3 4 6 ) 0. 0 0 0. 0 0 10 0 . 0 0 10 0 . 0 0 0. 0 0 0. 0 0 St e a m P l a n t ( 3 1 0 - 3 1 6 ) 1 40 . 6 2 57 . 1 0 0. 0 0 0. 0 0 59 . 3 8 42 . 9 0 1 ( P C e n e r g y c l a s s i f i c a t i o n r e f l e c t s s y s t e m l o a d f a c t o r ; d e m a n d c l a s s i f i c a t i o n re f l e c t s t h e v a l u e ( 1 - s y s t e m l o a d f a c t o r ) . T a t u m d i r e c t a t 2 9 . Ex h i b i t N o . 6 0 7 Ca s e N o . I P C _ E - 0 7 - 0 8 D. G o i n s , D O E Pa g e 1 o f 1 STATE OF IDAHO BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. IPC-E-08-10 IN THE MATTER OF TH APPLICATION OF IDAHO POWER COMPAN FOR AUTHORITY TO INCREASE ITS RATES AN CHAGES FOR ELECTRIC SERVICE TO ELECTRIC CUSTOMERS IN THE STATE OF IDAHO EXHBIT NO. 608 OF DR. DENNIS W. GOINS ON BEHAF OF THE U.S. DEPARTMENT OF ENERGY October 24, 2008 ID A H O P O W E R C O M P A N Y 3C P / 1 2 C P C L A S S C O S T O F S E R V I C E S T U D Y - R E V E N U E R E Q U I R E M E N T S U M l o y . ä TW E L V E M O N T H S E N D I N G D E C E M B E R 3 1 , 2 0 0 8 4 5 (I) (J ) (K ) (l ) (M ) (N ) 6 SO U R C E S UN M E T E R E D MU N I C I P A L TR A F I C SC SC SC 7 SN O T E S TO T A l GE N S E R V I C E ST L I G H T CO N T R O L DO E J N l JR S I M P l O T MIC R O N 8 (4 0 ) (4 1 ) (4 2 ) 9 10 T O T A l R A T E B A S E 2.0 9 4 , 7 8 7 , 5 1 2 2.6 9 4 , 0 5 5 3,1 7 3 , 2 4 5 52 7 , 1 3 3 16 , 7 7 7 , 9 0 0 17 , 5 2 3 . 3 6 1 55 , 8 0 7 . 8 6 3 11 12 R E N U E S F R O M R A T E S 0 13 RE T A I L 67 3 , 1 6 9 , 5 4 0 96 6 , 4 9 1 2,3 1 4 , 2 6 1 15 5 , 2 0 3 5,8 2 8 . 1 7 5 5,0 1 8 , 1 5 9 20 , 0 0 3 , 9 5 8 14 15 T O T A l S A l S R E V E N U E S 67 3 . 1 6 9 , 5 4 0 96 6 , 9 1 2,3 1 4 ~ 6 1 15 5 , 2 0 3 5,8 2 8 . 1 7 5 5,0 1 8 . 1 5 9 20 . 0 0 3 , 9 5 8 16 17 T O T A l O T H E R O P E R A T I N G R E V E N U E S 13 6 , 7 2 2 , 4 4 3 15 1 , 0 3 8 36 8 , 6 1 4 37 , 9 5 0 1, 7 5 9 , 1 9 5 2,0 9 0 , 9 0 4 5, 8 2 2 . 5 8 1 18 19 T O T A l R E V E N U E S 80 9 , 8 9 1 , 9 8 3 1. 1 1 7 , 5 2 9 2,6 8 2 , 8 7 5 19 3 , 1 5 3 7,5 8 7 , 3 7 0 7,1 0 9 , 0 6 3 25 , 8 2 6 , 5 3 9 20 21 O P E R T I N G E X E N S E S 0 22 WI T H O U T I N C T A X 66 2 , 5 3 1 , 2 8 2 83 8 , 3 1 3 1,8 9 8 , 0 3 3 18 2 , 1 6 9 6,6 8 2 , 4 4 1 6,1 4 2 , 1 6 9 23 , 0 6 , 7 4 7 23 0 24 O P E R A T I N G I N C O M E 0 25 BE F O R E I N C O M E T A X S 14 7 , 3 6 0 , 7 0 0 27 9 , 2 1 6 78 4 . 8 4 3 10 , 9 8 5 90 4 , 9 2 9 96 6 , 8 9 4 2,7 6 1 , 7 9 3 26 27 T O T A L F E D E R A IN C O M E T A X 19 , 0 6 2 , 4 3 9 24 , 5 1 6 28 , 8 7 6 4,7 9 7 15 2 , 6 7 8 15 9 , 4 6 2 50 7 , 8 4 8 28 T O T A L S T A T E I N C O M E T A X (3 . 6 6 1 , 4 7 9 ) (4 , 7 0 9 ) (5 , 5 4 7 ) (9 2 1 ) (2 9 , 3 2 6 ) (3 0 , 6 2 9 ) (9 7 , 5 4 7 ) 29 30 T O T A l O P E R A T I N G E X E N S E S 67 7 . 9 3 2 , 2 4 3 85 8 , 1 2 0 1.9 2 1 , 3 6 3 18 6 , 0 4 4 6, 8 0 5 . 7 9 3 6. 2 7 1 , 0 0 1 23 , 7 5 , 0 4 8 31 32 T O T A l O P E R T I N G I N C O M E 13 1 , 9 5 9 , 7 4 0 25 9 , 4 0 9 76 1 , 5 1 3 7,1 0 9 78 1 , 5 7 7 83 8 , 0 6 2 2.3 5 1 , 4 9 1 33 0 34 AD D : I E R C O O P E R A T I N G I N C O M E El 0 6,4 7 2 . 7 0 3 7,7 6 7 10 , 3 5 6 1,9 4 2 95 . 1 4 9 85 , 4 4 0 31 5 , 8 6 8 35 C O N S O L I D A T E D O P E R I N C O M E 13 8 , 4 3 2 , 4 4 3 26 7 , 1 7 7 77 1 , 8 6 9 9,0 5 1 87 6 , 7 2 6 92 3 , 5 0 1 2,6 6 7 , 3 5 9 36 37 R A T E S O F R E T U R N 6.6 0 8 9.9 1 7 24 . 3 2 4 1.7 1 7 5.2 5 5.2 7 0 4.7 8 0 38 R A T E S O F R E T U R N - I N D E X 1; 0 0 0 1.5 0 1 3.6 8 1 0.2 6 0 0.7 9 1 0.7 9 7 0.7 2 39 A V E R A G E M i l l S / K W 53 . 7 1 5 57 . 7 4 10 4 . 7 9 36 . 8 9 27 . 1 1 26 . 4 7 28 . 4 4 40 41 R E V E N U E R E Q U I R E M E N T C A L C U L A T I O N 42 R A T E O F R E T U R N R E Q U I R E D 8.5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 43 44 R E Q U I R E D R E V E N U E 73 9 , 9 5 2 , 7 8 2 90 6 , 0 0 8 1,4 9 2 , 3 4 7 21 4 , 3 4 6.7 4 4 , 0 5 7 5,9 6 1 , 8 9 2 23 , 4 5 9 , 0 7 6 45 R E V E N U E D E F I C I E N C Y 66 , 7 8 3 , 2 4 2 (6 0 , 4 8 3 ) (8 2 1 , 9 1 4 ) 59 , 1 4 3 91 5 , 8 8 2 94 3 , 7 3 3 3,4 5 5 , 1 1 8 46 P E R C E N T C H A N G E R E Q U I R E D 9.9 2 -6 . 2 6 % -3 5 . 5 2 % 38 . 1 1 % 15 . 7 1 % 18 . 8 1 % 17 . 2 7 % 47 R E T U R N AT C L A M E D R O R 17 9 , 1 0 4 , 3 3 2 23 0 . 3 4 2 27 1 , 3 1 2 45 , 0 7 0 1,4 3 4 , 5 1 0 1,4 9 8 , 2 4 7 4.7 7 1 . 5 7 2 48 E A N I N G S D E F I C I E N C Y 40 , 6 7 1 , 8 8 9 (3 6 , 8 3 5 ) (5 0 0 , 5 5 7 ) 36 , 0 1 9 55 7 , 7 8 4 57 4 , 7 4 6 2,1 0 4 . 2 1 3 49 50 R E V E N U E R E Q U I R E M E N T F O R R A T E D E S I G N 51 T O T A L I D A H O S A L E S R E V E N U E S 67 3 , 1 6 9 , 5 4 0 96 , 4 9 1 2. 3 1 4 , 2 6 1 15 5 ~ 0 3 5,8 2 8 . 1 7 5 5.0 1 8 , 1 5 9 20 , 0 0 3 , 9 5 8 52 53 R E Q U E S T E D C H A G E I N R E E N U E ( % ) 9. 9 2 % -6 . 2 6 % -3 5 . 5 2 % 38 . 1 1 % 15 . 7 1 % 18 . 8 1 % 17 . 2 7 % 54 55 S A L E S R E V E N U E R E Q U I R E D 73 9 , 9 5 2 , 7 8 2 90 6 , 0 0 8 1.4 9 2 , 3 4 7 21 4 . 3 4 6 6,7 4 4 , 0 5 7 5,9 6 1 , 8 9 2 23 , 4 5 9 , 0 7 6 56 R A T E O F R E T U R N A T R E Q U I R E D R E V E N U E 8. 5 5 0 8. 5 5 0 8.5 5 0 8. 5 5 0 8.5 5 0 8.5 5 0 8. 5 5 0 57 R E Q U E S T E D A V E R A G E M i l l S K W H 59 . 0 4 54 . 1 3 67 . 5 8 50 . 9 5 31 . 7 31 . 5 33 . 3 5 58 59 A C T U A l R A T E O F R E T U R N ( S A l E S R E V E N U E O N L Y ) (0 . 2 3 ) 4. 0 2 12 . 3 8 .5 . 5 -5 . 8 3 -7 . 1 5 -6 . 2 60 R E Q U E S T E D R A T E O F R E T U R N ( S A L E S R E V E N U E O N L Y ) 2.9 6 1.8 -1 3 . 5 2 5.3 7 .0 . 3 7 .1 . 6 .0 . 0 3 Ex h i b i t N o . 6 0 8 3C P / 1 2 C P Ca s e N O . I P C - E - 0 8 - 1 0 Mo d i f i e d D e m a n d ( 5 7 % ) / E n e r g y ( 4 3 % ) S p l i t D. G o i n s , D O E Hy d r o a n d A c e . 5 5 5 - - 5 0 % B a s e l o a d / 5 0 % P e a k i n g Pa g e 2 o f 2 STATE OF IDAHO BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION CASE NO. IPC-E-08-10 IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPAN FOR AUTHORITY TO INCREASE ITS RATES AND CHAGES FOR ELECTRIC SERVICE TO ELECTRC CUSTOMERS IN THE STATE OF IDAHO EXHBIT NO. 609 OF DR. DENNS W. GOINS ON BEHAF OF THE U.S. DEPARTMENT OF ENERGY October 24, 2008 1 ID A H O P O W E R C O M P A N Y 2 PE A K A N D A V E R A G E C L A S S C O S T O F S E R V I C E S T U D Y 3 - R E V E N U E R E Q U I R E M E N T S U M M A R Y - TW E L V E M O N T H S E N D I N G D E C E M B E R 3 1 , 2 0 0 8 4 5 (Q (J ) (K ) (L ) (M ) (N ) 6 SO U R C E S UN M E T E R E D MU N I C I P A L TR A F F I C SC SC SC 7 & NO T E S TO T A L GE N S E R V I C E ST L I G H T CO N T R O L DO E J I N L JR S I M P L O T MI C R O N 8 (4 0 ) (4 1 ) (4 2 ) 9 10 T O T A L R A T E B A S E 2,0 9 5 , 3 7 4 , 5 8 9 2.7 1 0 , 8 3 2 3,1 5 1 , 7 9 7 50 9 , 5 8 16 , 2 8 7 , 6 5 6 17 , 5 3 7 , 8 0 4 56 , 2 7 7 , 1 5 5 11 12 R E V N U E S F R O M R A T E S 0 13 RE T A I L 67 3 , 1 6 9 , 5 4 0 96 6 , 4 9 1 2,3 1 4 , 2 6 1 15 5 , 2 0 3 5, 8 2 8 . 1 7 5 5,0 1 8 , 1 5 9 20 . 0 0 3 . 9 5 8 14 15 T O T A L S A L E S R E V E N U E S 67 3 . 1 6 9 , 5 4 0 96 6 , 4 9 1 2.3 1 4 , 2 6 1 15 5 , 2 0 3 5, 8 2 8 , 1 7 5 5,0 1 8 , 1 5 9 20 . 0 0 3 . 9 5 8 18 17 T O T A L O T H E R O P E R A T I N G R E V N U E S 13 6 , 7 2 2 , 4 4 3 15 1 , 1 0 5 36 8 , 6 0 4 37 , 8 9 8 1, 7 5 7 , 8 3 7 2.0 9 1 , 1 2 2 5,8 2 4 , 5 9 1 16 19 T O T A L R E V E N U E S 80 9 , 8 9 1 , 9 8 3 1, 1 1 7 , 5 9 6 2,6 8 2 , 8 6 5 19 3 , 1 0 1 7, 5 8 6 , 0 1 2 7.1 0 9 , 2 8 1 25 , 8 2 8 , 5 4 9 20 21 O P E R A T I N G E X E N S E S 0 22 WIT H O U T I N C T A X 66 2 , 5 3 1 , 2 8 2 84 6 , 0 0 6 1, 9 0 0 , 0 4 0 17 6 , 9 0 1 6, 5 5 2 , 8 7 5 6,1 7 5 , 0 5 7 23 . 3 0 5 . 3 2 8 23 0 24 O P E R A T I N G I N C O M E 0 25 BE F O R E I N C O M E T A X E S 14 7 , 3 6 0 , 7 0 0 27 1 , 5 9 0 78 2 , 8 2 5 16 . 2 0 0 1, 0 3 3 , 1 3 6 93 4 , 2 2 4 2,5 2 3 , 2 2 2 26 27 T O T A L F E D E R A L I N C O M E T A X 19 , 0 6 2 , 4 3 9 24 , 6 6 1 28 , 6 7 3 4,6 3 7 14 8 , 1 7 5 15 9 , 5 4 8 51 1 , 9 7 5 28 T O T A L S T A T E I N C O M E T A X (3 , 6 6 1 , 4 7 9 ) (4 , 7 3 7 ) (5 , 5 0 7 ) (8 9 1 ) (2 8 , 4 6 1 ) (3 0 , 6 4 6 ) (9 8 , 3 3 9 ) 29 30 T O T A L O P E R A T I N G E X P E N S E S 67 7 , 9 3 2 , 2 4 3 86 5 , 9 3 0 1,9 2 3 , 2 0 6 18 0 , 6 4 7 6.6 7 2 , 5 8 9 6,3 0 3 , 9 6 0 23 , 7 1 8 , 9 6 4 31 32 T O T A L O P E R A T I N G I N C O M E 13 1 , 9 5 9 , 7 4 0 25 1 , 6 6 6 75 9 , 6 5 9 12 , 4 5 4 91 3 , 4 2 2 80 5 , 3 2 1 2, 1 0 9 , 5 8 6 33 0 34 AD D : I E R C O O P E R A T I N G I N C O M E El 0 6, 4 7 2 , 7 0 3 7,7 6 7 10 , 3 5 6 1, 9 4 2 95 , 1 4 9 85 , 4 4 0 31 5 , 8 6 8 35 C O N S O L I D A T E D O P E R I N C O M E 13 8 , 4 3 2 , 4 4 3 25 9 , 4 3 3 77 0 , D 5 14 , 3 9 6 1, 0 0 8 , 5 7 1 89 0 , 7 6 1 2, 4 2 5 , 4 5 4 36 37 R A T E S O F R E T U R N 6,6 0 7 9.5 7 0 24 . 4 3 1 2.8 2 5 6.1 9 2 5. 0 7 9 4.3 1 0 38 R A T E S O F R E T U R N - I N D E X 1. 0 0 0 1.4 4 9 3. 6 9 8 0. 4 2 8 0.9 3 7 0. 7 6 9 0. 6 5 2 39 A V E R A G E M I L L S / K W H 53 . 7 1 5 57 . 7 4 10 4 . 7 9 36 . 8 9 27 . 1 1 26 . 4 7 28 . 4 4 40 41 R E V E N U E R E Q U I R E M E N T C A L C U L A T I O N 42 R A T E O F R E T U R N R E Q U I R E D 8. 5 5 0 8.5 5 0 8.5 5 0 8. 5 5 0 8.5 5 0 8.5 5 0 8. 5 5 0 43 44 R E Q U I R E D R E V E N U E 74 0 , 0 3 5 , 2 0 2 92 1 , 0 7 8 1,4 9 2 . 3 8 0 20 3 , 1 1 7 6.4 5 8 , 7 4 2 6,0 1 7 , 6 8 0 23 , 9 2 2 . 1 6 9 45 R E V E N U E D E F I C I E N C Y 66 , 8 6 5 . 6 6 2 (4 5 , 4 1 3 ) (8 2 1 , 8 8 1 ) 47 . 9 1 4 63 0 , 5 6 7 99 9 , 5 2 1 3,9 1 8 , 2 1 1 46 P E R C E N T C H A N G E R E Q U I R E D 9. 9 3 -4 . 7 0 % -3 5 . 5 1 % 30 . 8 7 % 10 : 8 2 % 19 . 9 2 % 19 . 5 9 % 47 R E T U R N A T C L A I M E D R O R 17 9 , 1 5 4 . 5 2 7 23 1 , 7 7 6 26 9 , 4 7 9 43 , 5 7 6 1,3 9 2 . 5 9 5 1,4 9 9 , 4 8 2 4,8 1 1 , 6 9 7 48 E A R N I N G S D E F I C I E N C Y 40 , 7 2 2 , 0 8 4 (2 7 . 6 5 7 ) (5 0 0 , 5 3 7 ) 29 , 1 8 0 38 4 , 0 2 3 60 8 , 7 2 1 2, 3 8 6 . 2 4 3 49 50 R E V E N U E R E Q U I R E M E N T F O R R A T E D E S I G N 51 T O T A L I D A H O S A L E S R E V E N U E S 67 3 . 1 6 9 , 5 4 0 96 6 , 4 9 1 2. 3 1 4 , 2 6 1 15 5 , 2 0 3 5,8 2 8 . 1 7 5 5,0 1 8 , 1 5 9 20 . 0 0 3 , 9 5 8 52 53 R E Q U E S T E D C H A N G E I N R E V E N U E ( % ) 9.9 3 % -4 . 7 0 % -3 5 . 5 1 % 30 . 8 7 % 10 . 8 2 % 19 . 9 2 % 19 . 5 9 % 54 55 S A L E S R E V E N U E R E Q U I R E D 74 0 , 0 3 5 , 2 0 2 92 1 . 0 7 8 1,4 9 2 , 3 8 0 20 3 , 1 1 7 6,4 5 8 , 7 4 2 6,0 1 7 , S 8 0 23 , 9 2 2 . 1 6 9 56 R A T E O F R E T U R N A T R E Q U I R E D R E V E N U E 8.5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 8. 5 5 0 8.5 5 0 57 R E Q U E S T E D A V E R A G E M I L L S / K W H 59 . 0 5 55 . 0 3 67 . 5 8 48 . 2 8 30 . 0 4 31 . 7 4 34 . 0 1 58 59 A C T U A L R A T E O F R E T U R N ( S A L E S R E V E N U E O N L Y ) (0 . 2 3 ) 3.7 1 12 . 4 1 -4 . 9 9 -5 . 1 8 -7 . 3 3 -6 . 6 0 60 R E Q U E S T E D R A T E O F R E T U R N ( S A L E S R E V E N U E O N L Y ) 2.9 6 2.0 3 -1 3 . 6 7 4.4 1 -1 . 3 1 -1 . 6 3 0. 3 6 Ex h i b i t N o . 6 0 9 Ca s e N o . I P C - E - 0 8 - 1 0 D. G o i n s , D O E Pe a k a n d A v e r a g e Pa g e 2 o f 2 STATE OF IDAHO BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION CASE NO. IPC-E-08-10 IN TH MATTER OF TH APPLICATION OF, IDAHO POWER COMPAN FOR AUTHORITY TO INCREASE ITS RATES AN CHAGES FOR ELECTRC SERVICE TO ELECTRC CUSTOMERS IN THE STATE OF IDAHO EXHIT NO. 610 OF DR. DENNS W. GOINS ON BEHAF OF THE U.S. DEPARTMENT OF ENERGY October 24, 2008 1 ID A H O P O W E R C O M P A N Y 2 W1 2 C P C L A S S C O S T O F S E R V I C E S T U D Y 3 - R E U E R E Q U I R E M E N T S U M M A Y - ' TW E L V E M O N T H S E N D I N G D E C E M B E R 3 1 . 2 0 0 8 4 5 (A ) (B ) (C ) (D ) (E ) (F ) (G ) (H ) 6 SO U R C E S GE N S R V GE N S R V AR E A LG P O W E R IR R I G A T I O N 7 & NO T E S TO T A L RE S I D E N T I A L GE N S R V PR I M A R Y SE C O N D A R Y LI G H T I N G PR I M A Y SE C O N D A R Y 8 (1 ) (7 ) (9 - P ) (9 - S ) (1 5 ) (l9 - P ) (2 4 - 5 ) 9 10 T O T A L R A T E B A S E 2,0 9 3 . 3 9 8 , 8 5 9 92 8 , 7 0 5 , 9 7 6 42 , 8 1 7 , 2 1 5 49 , 9 1 0 , 0 3 2 43 3 , 3 2 3 , 0 5 5 89 6 , 7 4 8 21 9 , 2 9 1 , 3 5 8 32 2 , 2 4 3 , 1 4 3 11 12 R E V U E S F R O M R A T E S 13 RE T A I L 67 3 . 1 6 9 . 5 4 31 7 . 9 5 6 , 4 6 1 15 . 1 6 1 , 3 7 9 15 , 5 3 5 , 0 8 9 14 1 , 9 0 9 . 1 7 6 1,0 0 4 , 5 0 8 70 , 2 7 1 , 1 0 6 77 , 0 4 5 . 5 7 4 14 15 T O T A L S A E S R E V E N U E S 67 3 , 1 6 9 , 5 4 0 31 7 , 9 5 6 , 4 6 1 15 , 1 6 1 , 3 7 9 15 , 5 3 5 , 0 8 9 14 1 , 9 0 9 , 1 7 6 1,0 0 4 , 5 0 8 70 , 2 7 1 , 1 0 6 77 . D 5 , 5 7 4 16 17 T O T A L O T H E R O P E R A T I N G R E V E N U E S 13 6 , 7 2 2 , 4 4 3 52 , 2 9 4 , 8 1 5 2,0 0 . 5 5 2 5.0 4 6 , 8 1 29 , 3 0 9 , 8 6 9 14 5 . 7 3 7 21 . 9 7 1 , 1 4 6 15 , 8 1 6 , 5 3 4 18 19 T O T A L R E E N U E S 80 9 , 8 9 1 , 9 8 3 37 0 , 2 5 1 , 2 7 6 17 . 1 6 1 . 9 3 1 20 , 5 8 1 , 5 7 0 17 , 2 1 9 . 0 4 5 1,1 5 0 , 2 4 5 92 , 2 4 2 , 2 5 2 92 , 8 6 2 , 1 0 8 20 21 O P E R A T I N G E X P E N S E S 22 WIT H O U T I N C T A X 66 2 , 5 3 1 , 2 8 2 28 6 , 6 9 1 , 9 5 5 13 , 9 0 4 , 2 8 6 16 , 2 8 0 , 9 2 3 13 8 , 7 4 7 , 4 5 7 81 3 , 2 2 7 77 , 9 1 4 , 0 9 0 89 , 1 5 2 , 1 6 3 23 24 O P E R A T I N G I N C O M E 25 BE F O R E I N C O M E T A X E S 14 7 , 3 6 0 , 7 0 0 83 , 5 5 9 , 3 2 0 3,2 5 7 . 6 4 5 4, 3 0 0 , 6 4 8 32 , 4 7 1 , 5 8 8 33 7 , 0 1 7 14 . 3 2 8 , 1 6 2 3,7 0 9 , 9 4 5 26 27 T O T A L F E D E R A L I N C O M E T A X 19 , 0 6 2 , 4 3 9 8,4 5 6 , 7 7 4 38 9 , 8 9 3 45 4 , 4 8 0 3,9 4 5 , 8 2 9 8,1 6 6 1,9 9 6 . 8 6 2 2. 9 3 4 , 3 3 8 28 T O T A L S T A T E I N C O M E T A X (3 , 6 6 1 , 4 7 9 ) (1 , 6 2 4 , 3 6 2 ) (7 4 . 8 9 0 ) (8 7 , 2 6 ) (7 5 7 , 9 0 8 ) (1 , 5 6 8 ) (3 8 3 , 5 5 4 ) (5 6 3 , 6 2 2 ) 29 30 T O T A L O P E R T I N G E X P E N S E S 67 7 , 9 3 2 , 2 4 3 29 3 , 5 2 4 , 3 6 7 14 , 2 1 9 , 2 8 9 16 , 6 4 8 . 1 0 7 14 1 , 9 3 5 , 3 7 8 81 9 , 8 2 5 79 . 5 2 7 , 3 9 8 91 . 5 2 2 , 8 7 8 31 32 T O T A L O P E R A T I N G I N C O M E 13 1 , 9 5 9 , 7 4 0 76 , 7 2 8 . 9 0 8 2.9 4 2 , 6 4 2 3,9 3 3 , 4 6 4 29 , 2 8 3 . 6 6 7 33 0 , 4 2 0 12 , 7 1 4 , 8 5 4 1,3 3 9 , 2 2 9 33 34 AD D : I E R C O O P E R A T I N G I N C O M E E1 0 6, 4 7 2 , 7 0 3 2, 4 3 0 , 9 0 2 90 , 9 6 2 18 7 , 6 7 1 1,5 1 6 , 7 4 5 2,7 9 8 97 0 , 3 3 7 75 9 , 9 5 4 35 C O N S O L I D A T E D O P E R I N C O M E 13 8 , 4 3 2 , 4 4 3 79 , 1 5 7 , 8 1 0 3,0 3 3 . 6 0 4 4.1 2 1 . 1 3 5 30 , 8 0 0 , 4 1 2 33 3 , 2 1 8 13 . 6 8 5 , 1 9 1 2,0 9 9 . 1 8 3 36 37 R A T E S O F R E T U R N 6.6 1 3 8.5 2 3 7. 8 5 8.2 5 7 7. 0 8 37 . 1 5 9 6.2 4 1 0.6 5 1 38 R A T E S O F R E T U R N - I N D E X , 1.0 0 0 1.2 8 9 1.0 7 1 1.2 4 9 1.0 7 5 5. 6 1 9 0.9 4 4 0.0 9 9 39 A V E R A G E M I L L S K W H 53 . 7 2 62 . 7 7 79 . 5 5 37 , 8 6 44 . 4 7 16 8 . 2 33 . 0 9 49 . 6 6 40 41 R E V N U E R E Q U I R E M E N T C A L C U L A n O N 42 R A T E O F R E T U R N R E Q U I R E D 8. 5 5 0 8.5 5 0 8.5 5 0 8. 5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 8. 5 5 0 43 44 R E Q U I R E D R E V E N U E 73 9 , 7 5 7 , 8 2 7 31 8 . 3 6 1 . 2 9 8 16 . 1 9 1 , 3 5 3 15 , 7 7 5 , 1 0 4 15 2 , 1 6 9 . 5 5 7 58 3 , 2 5 9 78 , 5 8 6 , 5 5 5 11 8 , 8 3 8 , 7 5 3 45 R E V E N U E D E F I C I E N C Y 66 , 5 8 8 , 2 8 7 40 4 , 8 3 7 1,0 2 9 . 9 7 4 24 0 , 0 1 5 10 , 2 6 0 , 3 8 1 (4 2 1 , 2 4 9 ) 8,3 1 5 , 4 4 9 41 , 7 9 3 . 1 7 9 46 P E R C E N T C H A G E R E Q U I R E D 9. 8 9 % 0.1 3 % 6.7 9 % 1.5 4 % 7,2 3 % -4 1 . 9 4 % 11 . 8 3 % 54 . 2 4 % 47 R E T U R N A T C L A M E D R O R 17 8 , 9 a 5 , 6 0 2 79 , 4 0 4 , 3 6 1 3,6 6 0 , 8 7 2 4, 2 6 7 , 3 0 8 37 . 0 4 9 , 1 2 1 76 , 6 7 2 18 , 7 4 9 , 4 1 1 27 . 5 5 1 , 7 8 9 48 E A N I N G S D E F I C I E N C Y 40 , 5 5 3 , 1 5 9 24 6 , 5 5 1 62 7 , 2 6 8 14 6 , 1 7 3 6,2 4 8 , 7 1 0 (2 5 6 , 5 4 6 ) 5,0 6 4 , 2 2 0 , 25 , 4 5 2 , 6 0 6 49 50 R E V N U E R E Q U I R E M E N T F O R R A T E D E S I G N 51 T O T A L I D A H O S A L S R E V E N U E S 67 3 , 1 6 9 , 5 4 0 31 7 , 9 5 6 , 4 6 1 15 , 1 6 1 , 3 7 9 15 , 5 3 5 , 0 8 9 14 1 , 9 0 9 , 1 7 6 1, 0 0 4 , 5 0 8 70 , 2 7 1 , 1 0 6 77 , 0 4 5 . 5 7 4 52 53 R E Q U E S T E D C H A N G E I N R E V E N U E ( % ) 9.8 9 0 / . 0.1 3 % 6. 7 9 % 1. 5 4 % 7,2 3 % -4 1 . 9 4 % 11 . 8 3 % 54 . 2 4 % 54 55 S A E S R E V N U E R E Q U I R E D 73 9 , 7 5 7 , 8 2 7 31 8 , 3 6 1 , 2 9 8 16 , 1 9 1 , 3 5 3 15 , 7 7 5 , 1 0 4 15 2 , 1 6 9 . 5 5 7 . 58 3 , 2 5 9 78 , 5 8 6 , 5 5 5 11 8 , 8 3 8 , 7 5 3 56 R A T E O F R E T U R N A T R E Q U I R E D R E V E N U E 8. 5 5 0 8.5 5 0 8. 5 5 0 8, 5 5 0 8,5 5 0 8. 5 5 0 8, 5 5 0 8.5 5 0 57 R E Q U E S T E D A V E R A G E M I L L S / K W H 59 . 0 3 62 . 8 5 84 . 9 6 38 . 4 5 47 . 6 8 97 . 9 1 37 . 0 1 76 . 6 0 58 59 A C T U A L R A T E O F R E T U R N ( S A E S R E V E N U E O N L Y ) -0 . 2 3 2.6 3 2,2 0 -2 . 2 3 -0 . 0 1 20 . 5 9 -4 , 2 2 -4 . 4 9 60 R E Q U E S T E D R A T E O F R E T U R N ( S A L E S R E V E N U E O N L Y ) 2.9 5 2.6 7 4. 6 1 -1 . 5 2.3 6 -2 6 . 3 8 -0 , 4 3 8. 4 8 W1 2 C P S t u d y Ex h i b i t N o . 6 1 0 De m a n d / E n e r g y S p l i Ca s e N O . I P C - E - 0 8 . 1 0 De m a n d = 4 0 . 6 2 % D. G o i n s , D O E En e r g y = 5 9 . 3 8 % Pa g e 1 o f 2 1 ID A H O P O W E R C O M P A N Y 2 W1 2 C P C L A S S C O S T O F S E R V I C E S T U D Y 3 - R E " N U E R E Q U I R E M E N T S U M M A R Y - lW E L V E M O N T H S E N D I N G D E C E M B E R 3 1 , 2 0 0 8 4 5 (I ) (J ) (K ) (l ) (M ) (N ) 6 SO U R C E S UN M E T E R E D MU N I C I P A L TR A F F I C SC SC SC 7 & NO T E S TO T A L GE N S E R V I C E ST L I G H T CO N T R O L DO E / I N L JR S I M P L O T MI C R O N 8 (4 0 ) (4 1 ) (4 2 ) 9 10 T O T A L R A T E B A S E 2, 0 9 3 . 3 9 8 , 8 5 9 2,7 1 6 , 8 7 0 3,1 5 0 , 7 0 6 51 1 . 3 6 0 16 , 1 4 5 , 7 0 9 17 , 5 3 4 , 9 0 8 56 , 1 5 1 , 7 7 9 11 12 R E V N U E S F R O M R A T E S 0 13 RE T A I L 67 3 , 1 6 9 , 5 4 0 96 6 , 4 9 1 2,3 1 4 , 2 6 1 15 5 , 2 0 3 5.8 2 8 , 1 7 5 5, 0 1 8 , 1 5 9 20 , 0 0 3 , 9 5 8 14 15 T O T A L S A L E S R E V E N U E S 67 3 , 1 6 9 , 5 4 0 96 6 , 4 9 1 2,3 1 4 , 2 6 1 15 5 , 2 0 3 5,8 2 8 , 1 7 5 5,0 1 8 , 1 5 9 20 , 0 0 3 , 9 5 8 16 17 T O T A L O T H E R O P E R A T I N G R E V E N U E S 13 6 . 7 2 2 , 4 4 3 15 2 , 7 1 7 36 6 , 0 6 5 38 , : U l 1,7 2 8 , 8 1 6 2,0 7 9 , 1 3 4 5. 7 7 2 , 2 3 6 18 19 T O T A L R E V E N U E S 80 9 , 8 9 1 , 9 8 3 1,1 1 9 , 2 0 8 2, 6 8 0 . 3 2 6 19 3 , 5 4 4 7,5 5 6 , 9 9 1 7,0 9 7 , 2 9 3 25 , 7 7 6 . 1 9 4 20 21 O P E R A T I N G E X E N S E S 0 22 WIT H O U T I N C T A X 66 2 , 5 3 1 , 2 8 2 85 0 , 6 8 8 1.9 1 5 , 6 5 9 17 7 , 9 7 6 6, 5 6 , 1 1 7 6,2 0 8 , 6 0 3 23 , 3 0 8 , 1 3 8 23 0 24 O P E R A T I N G I N C O M E 0 25 BE F O R E I N C O M E T A X S 14 7 , 3 6 0 , 7 0 0 26 8 , 5 2 0 76 4 , 6 6 7 15 , 5 6 9 99 0 , 8 7 4 88 8 , 6 9 0 2,4 6 8 , 0 5 5 26 27 T O T A L F E D E R A I N C O M E T A X 19 , 0 6 2 . 4 3 9 24 , 7 4 0 28 , 6 9 0 4, 6 5 6 14 7 , 0 2 2 15 9 , 6 7 51 1 , 3 1 7 28 T O T A L S T A T E I N C O M E T A X (3 , 6 6 1 . 4 7 9 ) (4 , 7 5 2 ) (5 , 5 1 1 ) (8 9 4 ) (2 8 , 2 4 0 ) (3 0 , 6 7 0 ) (9 8 , 2 1 3 ) 29 30 T O T A L O P E R A T I N G E X E N S E S 67 7 , 9 3 2 , 2 4 3 87 0 , 6 7 6 1,9 3 8 . 8 3 9 18 1 , 7 3 8 6,6 8 4 , 9 0 0 6,3 3 7 , 6 0 6 23 , 7 2 1 , 2 4 2 31 32 T O T A L O P E R A T I N G I N C O M E 13 1 , 9 5 9 , 7 4 0 24 8 , 5 3 2 74 1 , 4 8 8 11 , 8 0 7 87 2 , 0 9 2 75 9 , 6 8 7 2, 0 5 4 , 9 5 1 33 0 34 AD D : I E R C O O P E R A T I N G I N C O M E El0 6, 4 7 2 , 7 0 3 7,8 6 6 10 , 3 8 4 1,9 6 9 94 , 2 9 9 85 , 1 5 8 31 3 , 6 5 6 35 C O N S O L I D A T E D O P E R I N C O M E 13 8 , 4 3 2 . 4 4 3 25 6 , 3 9 8 75 1 , 8 7 2 13 , 7 7 5 96 6 , 3 9 1 84 , 8 4 5 2.3 6 8 , 6 0 9 36 37 R A T E S O F R E T U R N 6.6 1 3 9. 4 3 7 23 . 8 6 4 2.6 9 4 5. 9 8 5 4.8 1 8 42 1 8 38 R A T E S O F R E T U R N . IN D E X 1.0 0 0 1A 2 7 3.6 0 9 0.4 0 7 0. 9 0 5 0. 7 2 9 0.6 3 8 39 A V E R A G E M I L L S / K W H 53 . 7 1 5 57 . 7 4 10 4 . 7 9 36 . 8 9 27 . 1 1 26 . 4 7 28 . 4 40 41 R E V E N U E R E Q U I R E M E N T C A L C U L A T I O N 42 R A T E O F R E T U R N R E Q U I R E D 8.5 5 0 8.5 5 0 8. 5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 43 44 R E Q U I R E D R E V E N U E 73 9 , 7 5 7 , 8 2 7 92 6 , 9 1 0 1,5 2 2 , 0 1 8 20 4 , 3 7 4 6,5 0 8 , 0 7 4 6,0 9 2 , 6 6 23 , 9 9 7 , 9 0 6 45 R E V E N U E D E F I C I E N C Y 66 , 5 8 8 , 2 8 7 (3 9 , 5 8 1 ) (7 9 2 , 2 4 3 ) 49 . 1 7 1 67 9 , 8 9 9 1,0 7 4 , 5 0 7 3, 9 9 3 , 9 4 8 46 P E R C E N T C H A G E R E Q U I R E D 9.8 9 -4 . 1 0 % -3 4 2 3 ° A o 31 . 6 8 % 11 . 6 7 % 21 . 4 1 % 19 . 9 7 % 47 R E T U R N A T C L A M E D R O R 17 8 , 9 8 5 , 6 0 2 23 2 , 2 9 26 9 , 3 8 5 43 , 7 2 1 1,3 8 0 , 5 8 1,4 9 9 , 2 3 5 4, 8 0 0 , 9 7 7 48 E A N I N G S D E F I C I E N C Y 40 , 5 5 3 , 1 5 9 (2 4 , 1 0 5 ) (4 8 2 , 4 8 7 ) 29 . 9 4 41 4 , 0 6 7 65 4 , 3 8 9 2, 4 3 2 , 3 6 8 49 50 R E V E N U E R E Q U I R E M E N T F O R R A T E D E S I G N 51 T O T A L I D A H O S A E S R E V E N U E S 67 3 , 1 6 9 , 5 4 0 96 6 , 4 9 1 2,3 1 4 , 2 6 1 15 5 , 2 0 3 5, 8 2 8 , 1 7 5 5,0 1 8 , 1 5 9 20 , 0 0 3 , 9 5 8 52 53 R E Q U E S T E D C H A G E I N R E V E N U E ( % ) 9.8 9 % -4 . 1 0 % -3 4 2 3 % .3 1 . 6 8 % 11 . 6 7 % 21 . 4 1 % 19 . 9 7 % 54 55 S A L E S R E V E N U E R E Q U I R E D 73 9 . 7 5 7 , 8 2 7 92 6 , 9 1 0 1, 5 2 2 , 0 1 8 20 4 , 3 7 4 6, 5 0 8 , 0 7 4 6,0 9 2 , 6 6 6 23 , 9 9 7 , 9 0 6 56 R A T E O F R E T R N A T R E Q U I R E D R E V E N U E 8.5 5 0 8.5 5 0 8. 5 5 0 8.5 5 0 8.5 5 0 8. 5 5 0 8.5 5 0 57 R E Q U E S T E D A V E R A G E M I L L S K W H 59 . 0 3 55 . 3 7 68 . 9 2 48 . 5 8 30 . 2 7 32 . 1 4 :U . 1 2 58 59 A C T U A L R A T E O F R E T U R N ( S A E S R E V E N U E O N L Y ) (0 . 2 3 ) 3.5 3 11 . 9 2 -5 . 1 9 -5 . 3 1 -7 . 5 2 ~. 6 2 60 R E Q U E S T E D R A T E O F R E T U R N ( S A L E S R E V E N U E O N L Y ) 2.9 5 2.0 7 -1 3 2 3 4.4 3 -1 . 1 0 -1 . 4 0 0.4 9 W1 2 C P S t u d y Ex h i b i t N o . 6 1 0 De m a n d / E n e r g y S p l i t Ca s e N O . / P C - E - D 8 - 1 0 De m a n d ' " 4 0 . 6 2 % D. G o i n s , D O E En e r g y = 5 9 . 3 8 % Pa g e 2 o f 2 STATE OF IDAHO BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. IPC-E-08-10 IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPAN FOR AUTHORITY TO INCREASE ITS RATES AN CHAGES FOR ELECTRC SERVICE TO ELECTRIC CUSTOMERS IN TH STATE OF IDAHO EXHBIT NO. 611 OF DR. DENNIS W. GOINS ON BEHAF OF THE U.S. DEPARTMENT OF ENERGY October 24, 2008 1 ID A H O P O W E R C O M P A N Y 2 W1 2 C P C L A S S C O S T O F S E R V I C E S T U D Y 3 - R E V E N U E R E Q U I R E M E N T S U M M A Y - lW E L V E M O N T H S E N D I N G D E C E M B E R 3 1 , 2 0 0 8 4 5 (A ) (B ) (C ) (D ) (E ) (F ) (G ) (H ) 6 SO U R C E S GE N S R V GE N S R V AR E A LG P O W E R IR R I G A T I O N 7 & NO T E S TO T A L RE S I D E N T I GE N S R V PR I M A R Y SE C O N D A R Y LIG H T I N G PR I M A R Y SE C O N D A R Y 8 (1 ) (7 ) (9 - P ) (9 - 8 ) (1 5 ) (lS - P ) (2 4 - 8 ) 9 10 T O T A L R A T E B A S E 2,0 9 3 , 3 9 8 , 8 5 9 93 0 , 1 6 7 , 9 4 3 42 , 7 7 7 . 3 1 0 49 . 4 9 2 , 5 8 4 43 0 , 9 5 8 , 0 7 0 85 9 . 1 9 9 21 5 , 6 6 2 , 7 3 3 33 0 , 1 8 5 . 8 9 7 11 12 R E V E N U E S F R O M R A T E S 13 RE T A I L 67 3 . 1 6 9 , 5 4 0 31 7 . 9 5 6 . 4 6 1 15 , 1 6 1 , 3 7 9 15 , 5 3 5 , 0 8 9 14 1 , 9 0 9 , 1 7 6 1, 0 0 4 . 5 0 8 70 , 2 7 1 , 1 0 6 77 , 0 4 5 , 5 7 4 14 15 T O T A L S A L E S R E V E N U E S 67 3 , 1 6 9 , 5 4 0 31 7 , 9 5 6 , 4 6 1 15 . 1 6 1 , 3 7 9 15 , 5 3 5 , 0 8 9 14 1 . 9 0 9 , 1 7 6 1,0 0 4 , 5 0 8 70 , 2 7 1 , 1 0 6 77 , 0 4 5 , 5 7 4 16 17 T O T A L O T H E R O P E R A T I N G R E V E N U E S 13 6 , 7 2 2 , 4 3 52 , 2 9 9 , 9 4 6 2, 0 0 0 , 4 1 2 5, 0 4 5 , 0 1 6 29 ) 0 1 , 5 6 9 14 5 , 6 0 5 21 ; 9 5 8 . 4 1 0 15 , 8 4 4 , 4 1 0 18 19 T O T A L R E V E N U E S 80 9 , 8 9 1 , 9 8 3 37 0 , 2 5 6 , 4 0 7 17 , 1 6 1 . 7 9 1 20 , 5 8 0 , 1 0 5 17 , 2 1 0 , 7 4 5 1,1 5 0 , 1 1 3 92 , 2 2 , 5 1 6 92 , 8 8 9 , 9 8 4 20 21 O P E R A T I N G E X P E N S E S 22 WIT H O U T I N C T A X 66 2 , 5 3 1 , 2 8 2 28 7 , 2 6 6 , 9 8 2 13 , 8 8 8 , 5 9 1 16 . 1 1 6 , 7 3 0 13 7 , 8 1 7 , 2 5 2 79 8 , 4 5 8 78 , 4 8 6 , 8 6 4 92 , 2 7 6 , 2 3 8 23 24 O P E R A T I N G I N C O M E 25 BE F O R E I N C O M E T A X E S 14 7 , 3 6 0 , 7 0 0 82 , 9 8 9 , 4 2 4 3, 2 7 3 , 2 0 0 4, 4 6 3 , 3 7 5 33 , 3 9 3 , 4 9 3 35 1 , 6 5 5 15 , 7 4 2 . 6 5 2 61 3 , 7 4 6 26 27 T O T A L F E D E R A I N C O M E T A X 19 , 0 6 2 , 4 3 9 8,4 7 0 , 0 8 7 38 9 , 5 2 9 45 0 , 6 7 8 3,9 2 4 , 2 9 4 7,8 2 4 1,9 6 3 , 8 2 0 3,0 0 6 , 6 6 5 28 T O T A L S T A T E I N C O M E T A X (3 . 6 6 1 , 4 7 9 ) (1 , 6 2 6 , 9 1 9 ) (7 4 , 8 2 0 ) (8 6 , 5 6 5 ) (7 5 3 , 7 7 1 ) (1 , 5 0 3 ) (3 7 7 , 2 0 7 ) (5 7 7 . 5 1 5 ) 29 30 T O T A L O P E R A T I N G E X P E N S E S 67 7 , 9 3 2 , 2 4 3 29 4 , 1 1 0 , 1 5 0 14 , 2 0 3 . 3 0 0 16 , 4 8 0 , 8 4 3 14 0 , 9 8 7 , 7 7 4 80 4 . 7 7 9 78 , 0 7 3 , 4 7 7 94 , 7 0 5 , 3 8 8 31 32 T O T A L O P E R T I N G I N C O M E 13 1 , 9 5 9 , 7 4 0 76 , 1 4 6 , 2 5 7 . 2 , 9 5 8 . 4 9 1 4,0 9 9 , 2 6 2 30 , 2 2 2 , 9 7 1 34 5 , 3 3 4 14 , 1 5 6 . 0 3 9 (1 , 8 1 5 , 4 0 4 ) 33 34 AD D : I E R C O O P E R A T I N G I N C O M E El0 6,4 7 2 , 7 0 3 2,4 3 0 , 9 0 2 90 , 9 6 2 18 7 , 6 7 1 1,5 1 6 , 7 4 5 2,7 9 8 97 0 , 3 3 7 75 9 . 9 5 4 35 C O N S O U D A T E D O P E R I N C O M E 13 8 , 4 3 2 , 4 4 3 78 , 5 7 7 , 1 5 8 3, 0 4 9 , 4 5 3 4, 2 8 6 , 9 3 4 31 , 7 3 9 , 7 1 5 34 8 , 1 3 2 15 , 1 2 6 . 3 7 7 (1 , 0 5 5 , 4 5 0 ) 36 37 R A T E S O F R E T U R N 6. 6 1 3 8.4 4 8 7.1 2 9 8.6 6 2 7.3 6 5 40 . 5 1 8 7. 0 1 4 -0 . 3 2 0 38 R A T E S O F R E T U R N - I N D E X 1.0 0 0 1. 2 7 7 1.0 7 8 1. 1 0 1.1 1 4 6.1 2 7 1.0 6 1 -0 . 0 4 8 39 A V E R A G E M I L L S K W 53 . 7 2 62 . 7 7 79 . 5 5 37 . 8 6 44 . 4 7 16 8 . 2 33 . 0 9 49 . 6 6 40 41 R E V E N U E R E Q U I R E M E N T C A L C U L A T I O N 42 R A T E O F R E T U R N R E Q U I R E D 8.5 5 0 8. 5 5 0 8,5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 43 44 R E Q U I R E D R E V E N U E 73 9 , 7 5 7 , 8 2 7 31 9 , 5 1 9 , 9 7 5 16 , 1 5 9 . 7 2 7 15 , 4 4 4 , 2 5 7 15 0 , 2 9 5 . 1 9 8 55 3 , 4 9 9 75 , 7 1 0 , 7 0 2 12 5 , 1 3 3 . 7 5 2 45 R E V E N U E D E F I C I E N C Y 66 , 5 8 8 , 2 8 7 1. 5 6 3 , 5 1 4 99 8 , 3 4 8 (9 0 , 8 3 2 ) 8, 3 8 6 , 0 2 2 (4 5 1 , 0 0 9 ) 5,4 3 9 , 5 9 6 48 , 0 8 8 . 1 7 8 46 P E R C E N T C H A G E R E Q U I R E D 9.8 9 % 0. 4 9 % 6.5 8 % -0 . 5 8 % 5. 9 1 % -4 4 . 9 0 % 7.7 4 % 62 . 4 2 % 47 R E T U R N A T C L A M E D R O R 17 8 , 9 8 5 , 6 0 2 79 , 5 2 9 , 3 5 9 3.6 5 7 , 4 6 0 4,2 3 1 . 6 1 6 36 , 8 4 6 , 9 1 5 73 , 4 6 1 18 , 4 3 9 , 1 6 4 28 , 2 3 0 , 8 9 4 48 E A N I N G S D E A C I E N C Y 40 , 5 5 3 , 1 5 9 95 2 , 2 0 1 60 8 , 0 0 7 (5 5 , 3 1 8 ) 5,1 0 7 . 1 9 9 (2 7 4 , 6 7 0 ) 3,3 1 2 , 7 8 7 29 , 2 8 6 , 3 4 49 50 R E V N U E R E Q U I R E E N T F O R R A T E D E S I G N 51 T O T A L I D A H O S A S R E V N U E S 67 3 , 1 6 9 , 5 4 0 31 7 , 9 5 6 , 4 6 1 15 . 1 6 1 , 3 7 9 15 , 5 3 5 . 0 8 9 14 1 , 9 0 9 . 1 7 6 1, 0 0 4 . 5 0 8 70 , 2 7 1 . 1 0 6 77 , 0 4 5 , 5 7 4 52 53 R E Q U E S T E D C H A G E I N R E V N U E ( % ) 9. 8 9 % 0.4 9 % 6.5 8 % -0 . 5 8 % 5.9 1 % -4 4 . 9 0 % 7. 7 4 % 62 . 4 2 % 54 55 S A E S R E V U E R E Q U I R E D 73 9 , 7 5 7 , 8 2 7 31 9 , 5 1 9 , 9 7 5 16 , 1 5 9 . 7 2 7 15 , 4 4 4 , 2 5 7 15 0 , 2 9 5 , 1 9 8 55 3 , 4 9 9 75 , 7 1 0 , 7 0 2 12 5 , 1 3 3 , 7 5 2 56 R A T E O F R E T U R N A T R E Q U I R E D R E V N U E 8. 5 5 0 8.5 5 0 8.5 5 0 8. 5 5 0 8.5 5 0 8.5 5 0 8. 5 5 0 8. 5 5 0 57 R E Q U E S T E D A V E R A G E M I L L S / K W H 59 . 0 3 63 , 0 8 84 . 7 9 37 . 6 4 47 . 1 0 92 . 9 1 35 . 6 5 80 . 6 6 58 59 A C T U A L R A T E O F R E T U R N ( S A E S R E V E N U E O N L Y ) -0 . 2 3 2.5 6 2. 2 -1 , 9 1 0.2 1 23 . 2 5 -3 . 6 2 .5 , 5 60 R E Q U E S T E D R A T E O F R E T U R N ( S A E S R E V N U E O N L Y ) 2. 9 5 2.7 3 4.5 7 .2 . 0 9 2.1 6 .2 9 . 2 5 -1 . 1 0 9. 2 W1 2 C P S t u d y Ex h i b i t N o . 6 1 1 De m a n d / E n e r g y S p l i t Ca s e N o . i P è . E 4 l S . 1 0 De m a n d = 5 7 . 1 0 % D. G o i n s , D O E En e r g y = 4 2 . 9 0 % Pa g e 1 o f 2 1 ID A H O P O W E R C O M P A N Y 2 W1 2 C P C L A S S C O S T O F S E R V I C E S T U D Y 3 - R E V N U E R E Q U R E M E N T S U M M A Y - lW E L V E M O N T H S E N D I N G D E C E M B E R 3 1 , 2 0 0 8 45 (I) (J ) (K ) (L ) (M ) (N ) 6 SO U R C E S UN M E T E R E D MU N C I P A L TR A F F I C SC SC SC 7 & NO T E S TO T A L GE N S E R V I C E ST L I G H T CO N T R O L DO E J N L JR S I M P L O T MIC R O N 8 (4 0 ) (4 1 ) (4 2 ) 910 T O T A L R A T E B A E 2.0 9 3 . 3 9 8 , 8 5 9 2,6 6 9 , 9 5 4 2, 9 9 2 . 0 2 0 49 9 , 5 8 7 15 , 5 7 2 , 9 5 0 17 , 0 2 0 , 0 2 8 54 , 5 4 0 , 5 8 3 1112 R E V N U E S F R O M R A T E S 0 13 RE T A I L 67 3 , 1 6 9 , 5 4 0 96 . 4 9 1 2,3 1 4 , 2 6 1 15 5 , 2 0 3 5, 8 2 8 , 1 7 5 5,0 1 8 , 1 5 9 20 , 0 0 3 , 9 5 8 1415 T O T A L S A L E S R E V E N U E S 67 3 , 1 6 9 , 5 4 0 96 6 , 4 9 1 2,3 1 4 . 2 6 1 15 5 , 2 0 3 5, 8 2 8 , 1 7 5 5,0 1 8 . 1 5 9 20 , 0 0 3 . 9 5 8 1617 T O T A L O T H E R O P E R A T I N G R E V N U E S 13 6 . 7 2 2 . 4 4 3 15 2 . 5 5 2 36 5 . 5 0 9 38 , 3 0 0 1,7 2 6 , 8 0 6 2,0 7 7 , 3 2 7 5,7 6 6 , 5 8 1 1819 T O T A L R E V U E S 80 9 , 8 9 1 , 9 8 3 1,1 1 9 , 0 4 3 2,6 7 9 , 7 7 0 19 3 . 5 0 3 7. 5 5 4 , 9 8 1 7, 0 9 5 , 4 8 6 25 . 7 7 0 . 5 3 9 2021 O P E R A T I N G E X E N S E S 0 22 WI H O U T I N C T A X 66 2 , 5 3 1 , 2 8 2 83 2 , 2 3 5 1,8 5 3 . 2 4 4 17 3 . 3 4 6 6,3 4 0 , 8 3 7 6,0 0 6 , 0 8 8 22 , 6 7 4 . 4 1 6 23 0 24 O P E R A T I N G I N C O M E 0 25 BE F O R E I N C O M E T A X S 14 7 , 3 6 0 . 7 0 0 28 6 , 8 0 8 82 6 , 5 2 5 20 , 1 5 8 1, 2 1 4 , 1 4 4 1,0 8 9 . 3 9 7 3, 0 9 6 , 1 2 3 2627 T O T A L F E D E R A I N C O M E T A X 19 , 0 6 2 , 4 3 9 24 , 3 1 3 27 , 2 4 5 4, 5 4 14 1 , 8 0 7 15 4 , 9 8 4 49 6 . 6 4 5 28 T O T A L S T A T E I N C O M E T A X (3 . 6 6 1 , 4 7 9 ) (4 , 6 7 0 ) (5 , 2 3 3 ) (8 7 4 ) (2 7 , 2 3 8 ) (2 9 , 7 6 9 ) (9 5 . 3 9 5 ) 2930 T O T A L O P E R A T I N G E X P E N S E S 67 7 , 9 3 2 , 2 4 3 85 1 . 8 7 7 1.8 7 5 . 2 5 6 17 7 , 0 2 1 6,4 5 5 . 4 0 6 6,1 3 1 , 3 0 3 23 . 0 7 5 , 6 6 7 3132 T O T A L O P E R A T I N G I N C O M E 13 1 , 9 5 9 , 7 4 0 26 7 , 1 6 6 80 4 , 5 1 3 16 , 4 8 2 1, 0 9 9 , 5 7 5 96 4 , 1 8 3 2. 6 9 4 , 8 7 2 33 0 34 AD D : I E R C O O P E R A T I N G I N C O M E El0 6,4 7 2 , 7 0 3 7.8 6 6 10 , 3 8 4 1,9 6 9 94 , 2 9 9 85 , 1 5 8 31 3 , 6 5 8 35 C O N S O L I D A T E O P E R I N C O M E 13 8 , 4 3 2 , 4 4 3 27 5 , 0 3 1 81 4 , 8 9 7 18 , 4 5 1 1. 1 9 3 . 8 7 4 1,0 4 9 , 3 4 1 3.0 0 8 , 5 3 0 3637 R A T E S O F R E T U R N 6. 6 1 3 10 . 3 0 1 27 , 2 3 6 3.6 9 3 7.6 6 6 6.1 6 5 5.5 1 6 38 R A T E S O F R E T U R N - I N D E X 1.0 0 0 1. 5 5 8 4.1 1 9 0.5 5 9 1. 1 5 9 0.9 3 2 0.8 3 4 39 A V E R A G E M I L L S / K W 53 . 7 1 5 57 . 7 4 10 4 . 7 9 36 . 8 9 27 . 1 1 26 . 4 7 28 , 4 4 4041 R E V E N U E R E Q I R R E M E N T C A L C U L A T I O N 42 R A T E O F R E T R N R E Q U I R E D 8. 5 5 0 8.5 5 0 8.5 5 0 8, 5 5 0 8.5 5 0 8.5 5 0 8.5 5 0 4344 R E Q U I R E D R E V E N U E 73 9 , 7 5 7 , 8 2 7 88 9 , 7 2 7 1,3 9 6 , 2 5 2 19 5 , 0 4 4 6,0 5 4 , 1 3 6 5,6 8 4 , 6 0 0 22 . 7 2 0 , 9 5 8 45 R E V E N U E D E F I C I E N C Y 66 . 5 8 6 , 2 8 7 (7 6 , 7 6 4 ) (9 1 8 , 0 0 9 ) 39 , 8 4 1 22 5 , 9 6 1 66 6 , 4 4 1 2, 7 1 7 , 0 0 0 46 P E R C E N T C H A N G E R E Q U I R E D 9.8 9 -7 . 9 4 % -3 9 . 6 7 % 25 . 6 7 % 3.8 8 % 13 . 2 8 % 13 . 5 8 % 47 R E T U R N A T C L A M E D R O R 17 8 . 9 8 5 , 6 0 2 22 8 , 2 8 1 25 5 . 8 1 8 42 , 7 1 5 1,3 3 1 , 4 8 7 1,4 5 5 , 2 1 2 4, 6 6 3 , 2 2 0 48 E A R N I N G S D E F I C I E N C Y 40 , 5 5 3 . 1 5 9 (4 8 , 7 5 0 ) (5 5 9 , 0 8 0 ) 24 , 2 6 4 13 7 , 6 1 3 40 5 , 8 7 1 1, 6 5 4 , 6 9 0 4950 R E V E N U E R E Q I R R E M E N T F O R R A T E D E S I G N 51 T O T A L I D A H O S A L E S R E V U E S 67 3 , 1 6 9 , 5 4 0 96 6 , 4 9 1 2,3 1 4 , 2 6 1 15 5 , 2 0 3 5,8 2 8 , 1 7 5 5,0 1 8 . 1 5 9 20 , 0 0 3 , 9 5 8 5253 R E Q U E S T E D C H A G E I N R E V E N U E ( % ) 9.8 9 % -7 . 9 4 % -- 9 . 6 7 % 25 . 6 7 % 3.8 8 % 13 , 2 8 % 13 . 5 8 % 5455 S A L E S R E V E N U E R E Q U I R E 73 9 , 7 5 7 , 8 2 7 88 9 , 7 2 7 1, 3 9 6 , 2 5 2 19 5 , 0 4 6,0 5 4 , 1 3 6 5, 6 8 4 , 6 0 0 22 , 7 2 0 , 9 5 8 56 R A T E O F R E T U R N A T R E Q U I R E D R E V E N U E 8.5 5 0 8.5 5 0 8. 5 0 8.5 5 0 8.5 5 0 8, 5 5 0 8. 5 5 0 57 R E Q U E S T E D A V E R A G E M I L L S / K W H 59 . 3 53 . 1 5 63 2 2 46 . 3 6 28 . 1 6 29 . 9 9 32 . 3 0 5859 A C T U A L R A T E O F R E T U R N ( S A L E S R E V N U E O N L Y ) (0 . 2 3 ) 42 9 14 . 6 7 .4 . 7 -4 . 0 3 -6 . 5 4 -5 . 6 3 60 R E Q U E S T E D R A T E O F R E T R N ( S A L E S R E V N U E O N L Y ) 2. 9 5 1.4 2 .1 6 . 0 3. 6 1 .2 . 5 8 -2 . 6 2 -0 . 6 5 W1 2 C P S t u d y Ex h i b i t N o . 6 1 1 De m a n d / E n e r g y S p l i t Ca s e N o . I P C - E - D S - 1 0 De m a n d = 5 7 . 1 0 % D. G o i n s , D O E En e r g y = 4 2 . 9 0 % Pa g e 2 o f 2 ApPENDIX QUALIFICATIONS OF DENNIS W. GOINS DENNS W. GOINS PRESENT POSITION Economic Consultant, Potomac Management Group, Alexandria, Virginia. ARAS OF QUALIFICATION . Competitive Market Analysis . Costing and Pricing Energy-Related Goods and Services . Utilty Planning and Operations . Litigation Analysis, Strategy Development, Expert Testimony PREVIOUS POSITIONS . Vice President, Hagler, Baily & Company, Washington, DC. . Principal, Resource Consulting Group, Inc., Cambridge, Massachusetts. . Senior Associate, Resource Planing Associates, Inc., Cambridge, Massachusetts. . Economist, North Carolina Utilities Commission, Raleigh, North Carolina. EDUCATION College Wake Forest University North Carolina State University North Carolina State University Major Degree Economics BA Economics ME Economics PhD RELEVANT EXPERIENCE Dr. Goins specializes in pricing, planning, and market structure issues affecting firms that buy and sell products in electricity and natural gas markets. He has extensive experience in evaluating competitive market conditions, analyzing power and fuel requirements~ prices, market operations, and transactions, developing product pricing strategies, setting rates for energy-related products and services, and negotiating power .supply and natural gas contracts for private and public entities. He has participated in more than 100 cases as an expert on competitive market issues, utilty restructuring, power market planning and operations, utilty mergers, rate design, cost of service, and management prudence DENNS W. GOINS before the Federal Energy Regulatory Commission, the First Judicial District Court of Montana, the Circuit Court of Kanawha County, West Virginia, the General Accounting Offce (now the Governent Accountabilty Offce), and regulatory commissions in Alabama, Arizona, Arkansas, Colorado, Florida, Georgia, Indiana, Idaho, Ilinois, Kentucky, Louisiana, Maine, Maryland, Massachusetts, Minnesota, Mississippi, New Jersey, New York, North Carolina, Ohio, Oklahoma, South Carolina, Texas, Utah, Vermont, Virginia, and the District of Columbia. He has also prepared an expert report on behalf of the United States regarding pricing and contract issues in a case before the United States Court of Federal Claims. PARTICIPATION IN REGULATORY, ADMINISTRATIVE, AN COURT PROCEEDINGS 1. South Carolina Electric & Gas Company, before the South Carolina Public Service Commission, Docket No. 2008-302-E (2008), on behalf of CMC Steel-SC, re fuel and purchased power cost recovery. 2. South Carolina Electric & Gas Company, before the South Carolina Public Service Commission, Docket No. 2008-196-E (2008), on behalf of CMC Steel-SC, re base load review order for a nuclear facilty. 3. Alabama Power Company, before the Alabama Public Service Commission, Docket No. 18148 (2008), on behalf of CMC Steel Alabama, Nucor Steel Birmingham, and Nucor Steel Tuscaloosa, re energy cost recovery. 4. Idaho Power Company, before the Idaho Public Utilties Commission, Case No. IPC-E-08-10 (2008), on behalf of the U.S. Deparment of Energy (Federal Executive Agencies), re cost-of-service and rate design issues. 5. Ohio Edison et ai., before the Public Utilities Commission of Ohio, Case No. 08-935-EL-SSO (2008), on behalf of Nucor Steel Marion, Inc., re energy security plan proposaL. 6. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case No. 08-936-EL-SSO (2008), on behalf of Nucor Steel Marion, Inc., re market rate offer proposaL. 7. Entergy Texas, Inc., before the Public Utilties Commission of Texas, PUC Docket No. 35269 (2008), on behalf of Texas Cities, re jurisdictional allocation of system agreement payments. 8. Duke Energy Indiana, Inc., before the Indiana Utilty Regulatory Commission, Cause No. 43374 (2008), on behalf of Nucor Steel and Steel Dynamics, Inc., re alternative regulatory plan. 2 DENNIS W. GOINS 9. Entergy Gulf States Inc., before the Public Utilities Commission of Texas, PUC Docket No. 34800 (2008), on behalf of Texas Cities, re affliate transactions. 10. Commonwealth Edison Company, before the Ilinois Commerce Commission, Docket No. 07-0566 (2008), on behalf of Nucor Steel Kankakee, Inc., re cost-of-service and rate design issues. 11. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case No. 07-0551-EL-AIR et al. (2008), on behalf of Nucor Steel Marion, Inc., re cost-of-service and rate design issues. 12. Appalachian Power Company dba American Electric Power, before the Public Service Commission of West Virginia, Case No. 06-0033-E-CN (2007), on behalf of Steel of West Virginia, Inc., re power plant cost recovery mechanism. 13. Oncor Electric Delivery Company and Texas Energy Futue Holdings Limited Partnership, before the Public Utilties Commission of Texas, PUC Docket No. 34077 (2007), on behalf of Nucor Steel - Texas, re acquisition ofTXU Corp. by Texas Energy Future Holdings Limited Parership. 14. Arkansas Oklahoma Gas Company, before the Arkansas Public Service Commission, Docket No. 07-026-U (2007), on behalf of. West Central Arkansas Gas Consumers, re gas cost-of-service and rate design issues. 15. Idaho Power Company, before the Idaho Public Utilities Commission, Case No. IPC-E-07-08 (2007), on behalf of the U.S. Deparment of Energy (Federal Executive Agencies), re cost-of-service and rate design issues. 16. Potomac Electric Power Company, before the District of Columbia Public Service Commission, Formal Case No. 1056 (2007), on behalf of the General Services Administration, re demand-side management and advanced metering programs. 17. South Carolina Electric & Gas Company, before the South Carolina Public Service Commission, Docket No. 2007-22-9-E (2007), on behalf of CMC Steel-SC, re cost-of-service and rate design issues. 18. Potomac Electric Power Company, before the Maryland Public Service Commission, Case No. 9092 (2007), on behalf of the General Services Administration, re retail cost allocation and standby rate design issues for distributed generation resources. 19. Potomac Electric Power Company, before the District of Columbia Public Service Commission, Formal Case No. 1053 (2007), on behalf of the General Services Administration, re retail cost allocation and standby rate design issues for distributed generation resources. 3 DENNS W. GOINS 20. Entergy Gulf States Inc., before the Public Utilties Commission of Texas, PUC Docket No. 32907 (2006), on behalf of Texas Cities, re hurricane cost recovery. 21. Entergy Gulf States Inc., before the Public Utilties Commission of Texas, PUC Docket No. 32710/ SOAH Docket No. 473-06-2307 (2006), on behalf of Texas Cities, re reconciliation of fuel and purchased power costs. 22. Florida Power & Light Company, before the Florida Public Service Commission, Docket No. 060001-EI (2006), on behalf of the U.S. Air Force (Federal Executive Agencies), re fuel and purchased power cost recovery. 23. Arizona Public Service Company, before the Arizona Corporation Commission, Docket No. E-01345A-05-0816 (2006), on behalf of the U.S. Air Force (Federal Executive Agencies), re retail cost allocation and rate design issues. 24. PacifiCorp (dba Rocky Mountain Power), before the Utah Public Service Commission, Docket No. 06-035-21 (2006), on behalf of the U.S. Air Force (Federal Executive Agencies), re rate design issues. 25. South Carolina Electric & Gas Company, before the South Carolina Public Service Commission, Docket No. 2006-2-E (2006), on behalf of CMC Steel-SC, re fuel and purchased power cost recovery. 26. Entergy Gulf States Inc., before the Public Utilities Commission of Texas, PUC Docket No. 31544/ SOAR Docket No. 473-06-0092 (2006), on behalf of Texas Cities, re transition to competition rider. 27. Idaho Power Company, before the Idaho Public Utilities Commission, Case No. IPC-E-05-28 (2006), on behalf of the U.S. Department of Energy (Federal Executive Agencies), re cost-of-service and rate design issues. 28. Alabama Power Company, before the Alabama Public Service Commission, Docket No. 18148 (2005), on behalf of SMI Steel-Alabama, re energy cost recovery. 29. Florida Power & Light Company, before the Florida Public Service Commission, Docket No. 050001-EI (2005), on behalf ofthe U.S. Air Force (Federal Executive Agencies), re fuel and capacity cost recovery. 30. Entergy Gulf States Inc., before the Public Utilities Commission of Texas, PUC Docket No. 31315/ SOAR Docket No. 473-05-8446 (2005), on behalf of Texas Cities, re incremental purchased capacity cost rider. 31. Florida Power & Light Company, before the Florida Public Service Commission, Docket No. 050045-EI (2005), on behalf of the U.S. Air Force (Federal Executive Agencies), re cost-of-service and interrptible rate issues. 4 DENNS W. GOINS 32. Arkansas Electric Cooperative Corporation, before the Arkansas Public Service Commission, Docket No. 05-042-U (2005), on behalf of Nucor Steel and Nucor- Yamato Steel, re power plant purchase. 33. Arkansas Electric Cooperative Corporation, before the Arkansas Public Service Commission, Docket No. 04-141-U (2005), on behalf of Nucor Steel and Nucor- Yamato Steel, re cost-of-service and rate design issues. 34. Dominion North Carolina Power, before the North Carolina Utilties Commission, Docket No. E-22, Sub 412 (2005), on behalf of Nucor Steel- Hertford, re cost-of-service and interruptible rate issues. ' 35. Public Service Company of Colorado, before the Colorado Public Utilities Commission, Docket No. 04S-164E (2004), on behalf of the U.S. Air Force (Federal Executive Agencies), re cost-of-service and interrptible rate issues. 36. CenterPoint Energy Houston Electric, LLC, et al., before the Public Utilty Commission of Texas, PUC Docket No. 29526 (2004), on behalf of the Coalition of Commercial Ratepayers, re stranded cost true-up balances. 37. PacifiCorp, before the Utah Public Service Commission, Docket No. 04- 035-11 (2004), on behalf of the U.S. Air Force (United States Executive Agencies), re time-of-day rate design issues. 38. Arizona Public Service Company, before the Arizona Corporation Commission, Docket No. E-01345A-03-0347 (2004), on behalf of the U.S. Air Force (Federal Executive Agencies), re retail cost allocation and rate design issues. 39. Idaho Power Company, before the Idaho Public Utilties Commission, Case No. IPC-E-03-13 (2004), on behalf of the U.S. Deparment of Energy (Federal Executive Agencies), re retail cost allocation and rate design issues. 40. PacifiCorp, before the Utah Public Service Commission, Docket No. 03- 2035-02 (2004), on behalf of the U.S. Air Force (United States Executive Agencies), re retail cost allocation and rate design issues. 41. Dominion Virginia Power, before the Virginia State Corporation Commission, Case No. PUE-2000-00285 (2003), on behalf of Chaparral (Virginia) Inc., re recovery of fuel costs. 42. Jersey Central Power & Light Company, before the New Jersey Board of Public Utilties, BPU Docket No. ER02080506, OAL Docket No. PUC- 7894-02 (2002-2003), on behalf of New Jersey Commercial Users, re retail cost allocation and rate design issues. 5 DENNS W. GOINS 43. Public Service Electric and Gas Company, before the New Jersey Board of Public Utilities, BPU Docket No. ER02050303, OAL Docket No. PUC- 5744-02 (2002-2003), on behalf of New Jersey Commercial Users, re retail cost allocation and rate design issues. 44. South Carolina Electric & Gas Company, before the South Carolina Public Service Commission, Docket No. 2002-223-E (2002), on behalf of SMI Steel-SC, re retail cost allocation and rate design issues. 45. Montana Power Company, before the First Judicial District Court of Montana, Great Falls Tribune et al. v. the Montana Public Service Commission, Cause No. CDV2001-208 (2002), on behalf of a media consortium (Great Falls Tribune, Bilings Gazette, Montana Standard, Helena Independent Record, Missoulian, Big Sky Publishing, Inc. dba Bozeman Daily Chronicle, the Montana Newspaper Association, Miles City Star, Livingston Enterprise, Yellowstone Public Radio, the Associated Press, Inc., and the Montana Broadcasters Association), re public disclosure of allegedly proprietary contract information. 46. Louisvile Gas & Electric et al., before the Kentucky Public Service Commission, Administrative Case No. 387 (2001), on behalf of Gallatin Steel Company, re adequacy of generation and transmission capacity in Kentucky. 47. PacifiCorp, before the Utah Public Service Commission, Docket No. 01- 035-01 (2001), on behalf of Nucor Steel, re retail cost allocation and rate design issues. 48. TXU Electric Company, before the Public Utilities Commission of Texas, PUC Docket No. 23640/ SOAH Docket No. 473-01-1922 (2001), on behalf ofNucor Steel, re fuel cost recovery. 49. FPL Group et al., before the Federal Energy Regulatory Commission, Docket No. ECOI-33-000 (2001), on behalf of Arkansas Electric Cooperative Corporation, Inc., re merger-related market power issues. 50. Entergy Mississippi, Inc., et al., before the Mississippi Public Service Commission, Docket No. 2000-UA-925 (2001), on behalf of Birmingham Steel-Mississippi, re appropriate regulatory conditions for merger approval. 51. TXU Electric Company, before the Public Utilties Commission of Texas, PUC Docket No. 22350/ SOAH Docket No. 473-00-1015 (2000), on behalf ofNucor Steel, re unbundled cost of service and rates. 52. PacifiCorp, before the Utah Public Service Commission, Docket No. 99- 035-10 (2000), on behalf of Nucor Steel, re using system benefit charges to fund demand-side resource investments. 6 DENNIS W. GOINS 53. Entergy Arkansas, Inc. et a!., before the Arkansas Public Service Commission, Docket No. 00-190-U (2000), on behalf of Nucor-Yamato Steel and Nucor Steel-Arkansas, re the development of competitive electric power markets in Arkansas. 54. Entergy Arkansas, Inc. et al., before the Arkansas Public Service Commission, Docket No. 00-048-R (2000), on behalf of Nucor-Yamato Steel and Nucor Steel-Arkansas, re generic filing requirements and guidelines for market power analyses. 55. ScottishPower and PacifiCorp, before the Utah Public Service Commission, Docket No. 98-2035-04 (1999), on behalf of Nucor Steel, re merger conditions to protect the public interest. 56. Dominion Resources, Inc. and Consolidated Natural Gas Còmpany, before the Virginia State Corporation Commission, Case No. PUA990020 (1999), on behalf of the City of Richmond, re market power and merger conditions to protectthe public interest. 57. Houston Lighting & Power Company, before the Public Utilty Commission of Texas, Docket No. 18465 (1998) on behalf of the Texas Commercial Customers, re excess earnings and stranded-cost recovery and mitigation. 58. PJM Interconnection, LLC, before the Federal Energy Regulatory Commission, Docket No. ER98-1384 (1998) on behalf of Wellsboro Electric Company, re pricing low-voltage distribution services. 59. DQE, Inc. and Allegheny Power System, Inc., before the Federal Energy Regulatory Commission, Docket Nos. ER97-4050-000, ER97-4051-000, and EC97-46-000 (1997) on behalf of the Borough of Chambersburg, re market power in relevant markets. 60. GPU Energy, before the New Jersey Board of Public Utilties, Docket No. E097070458 (1997) on behalf of the New Jersey Commercial Users Group, re unbundled retail rates. 61. GPU Energy, before the New Jersey Board of Public Utilities, Docket No. E097070459 (1997) on behalf of the New Jersey Commercial Users Group, re stranded costs. 62. Public Service Electric and Gas Company, before the New Jersey Board of Public Utilities, Docket No. E097070461 (1997) on behalf of the New Jersey Commercial Use.rs Group, re unbundled retail rates. 63. Public Service Electric and Gas Company, before the New Jersey Board of Public Utilties, Docket No. E097070462 (1997) on behalf of the New Jersey Commercial Users Group, re stranded costs. 7 DENNIS W. GOINS 64. DQE, Inc. and Allegheny Power System, Inc., before the Federal Energy Regulatory Commission, Docket Nos. ER97-4050-000, ER97-4051-000, and EC97-46-000 (1997) on behalf of the Borough of Chambersburg, Allegheny Electric Cooperative, Inc., and Selected Municipalities, re market power in relevant markets. 65. CSW Power Marketing, Inc., before the Federal Energy Regulatory Commission, Docket NO.ER97-1238-000 (1997) on behalf of the Transmission Dependent Utility Systems, re market power in relevant markets. 66. Central Hudson Gas & Electric Corporation et al., before the New York Public Service Commission, Case Nos. 96-E-0891, 96-E-0897, 96-E-0898, 96-E-0900, 96-E-0909 (1997), on behalfofthe Retail Council of New York, re stranded-cost recovery. 67. Central Hudson Gas & Electric Corporation, supplemental testimony, before the New York Public Service Commission, Case No. 96-E-0909 (1997) on behalf of the Retail Council of New York, re stranded-cost recovery. 68. Consolidated Edison Company of New York, Inc., supplemental testimony, before the New York Public Service Commission, Case No. 96-E-0897 (1997) on behalf of the Retail Council of New York, re stranded-cost recovery. 69. New York State Electric & Gas Corporation, supplemental testimony, before the New York Public Service Commission, Case No. 96-E-0891 (1997) on behalf of the Retail Council of New York, re stranded-cost recovery. 70. Rochester Gas and Electric Corporation, supplemental testimony, before the New York Public Service Commission, Case No. 96-E-0898 (1997) on behalf of the Retail Council of New York, re stranded-cost recovery. 71. Texas Utilities Electric Company, before the Public Utility Commission of Texas, Docket No. 15015 (1996), on behalf of Nucor Steel-Texas, re real. . time electricity pricing. 72. Central Power and Light Company, before the Public Utility Commission of Texas, Docket No. 14965 (1996), on behalf of the Texas Retailers Association, re cost of service and rate design. 73. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 95-1076-E (1996), on behalf of Nucor Steel- Darlington, re integrated resource planning. 74. Texas Utilities Electric Company, before the Public Utilty Commission of Texas, Docket No. 13575 (1995), on behalf of Nucor Steel-Texas, re integrated resource planning, DSM options, and real-time pricing. 8 DENNIS W. GOINS 75. Arkansas Power & Light Company, et ai., Notice of Inquiry to Consider Section 111 of the Energy Policy Act of 1992, before the Arkansas Public Service Commission, Docket No. 94-342-U (1995), Initial Comments on behalf of Nucor-Yamato Steel Company, re integrated resource planning standards. 76. Arkansas Power & Light Company, et ai., Notice of Inquiry to Consider Section 111 of the Energy Policy Act of 1992, before the Arkansas Public Service Commission, Docket No. 94-342-U (1995), Reply Comments on behalf of Nucor- Yamato Steel Company, re integrated resource planning standards. 77. Arkansas Power & Light Company, et ai., Notice of Inquiry to Consider Section 111 of the Energy Policy Act of 1992, before the Arkansas Public Service Commission, Docket No. 94-342-U (1995), Final Comments on behalf of Nucor-Yamato Steel Company, re integrated resource planning standards. 78. South Carolina Pipeline Corporation, before the South Carolina Public Service Commission, Docket No. 94-202-G (1995), on behalf of Nucor Steel, re integrated resource planning and rate caps. 79. Gulf States Utilties Company, before the United States Court of Federal Claims, Gulf States Utilities Company v. the United States, Docket No. 91- 1118C (1994, 1995), on behalf of the United States, re electricity rate and contract dispute litigation. 80. American Electric Power Corporation, before the Federal Energy Regulatory Commission, Docket No. ER93-540-000 (1994), on behalf of DC Tie, Inc., re costing and pricing electicity transmission services. 81. Texas Utilities Electric Company, before the Public Utilty Commission of Texas, Docket No. 13100 (1994), on behalf of Nucor Steel-Texas, re real- time electricity pricing. 82. Carolina Power & Light Company, et ai., Proposed Regulation Governing the Recovery of Fuel Costs by Electric Utilities, before the South Carolina Public Service Commission, Docket No. 93-238-E (1994), on behalf of Nucor Steel-Darlington, re fuel-cost recovery. 83. Southern Natural Gas Company, before the Federal Energy Regulatory Commission, Docket No. RP93-15-000 (1993-1995), on behalf of Nucor Steel-Darlington, re costing and pricing natural gas transportation services. 84. West Penn Power Company, et ai., v. State Tax Departent of West Virginia, et ai., Civil Action No. 89-C-3056 (1993), before the Circuit Court of Kanawha County, West Virginia, on behalf of the West Virginia Department of Tax and Revenue, reelectricity generation tax. 9 DENNS W. GOINS 85. Carolina Power & Light Company, et al., Proceeding Regarding Consideration of Certain Standards Pertaining to Wholesale Power Purchases Pursuant to Section 712 of the 1992 Energy Policy Act, before the South Carolina Public Service Commission, Docket No. 92-231-E (1993), on behalf ofNucor Steel-Darlington, re Section 712 regulations. 86. Mountain Fuel Supply Company, before the Public Service Commission of Utah, Docket No. 93-057-01 (1993), on behalf of Nucor Steel-Utah, re costing and pricing retail natural gas firm, interrptible, and transportation services. 87. Texas Utilties Electric Company, before the Public Utilty Commission of Texas, Docket No. 11735 (1993), on behalf of the Texas Retailers Association, re retail cost-of-service and rate design. 88. Virginia Electric and Power Company, before the Virginia State Corporation Commission, Case No. PUE920041 (1993), on behalf of Philp Morris USA, re cost of service and retail rate design. 89. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 92-209-E (1992), on behalf of Nucor Steel- Darlington. 90. Gulf States Utilties Company, before the Louisiana Public Service Commission, Docket No. U-17282, Rate Design (1992), on behalf of the Department of Energy, Strategic Petroleum Reserve. 91. Georgia Power Company, before the Georgia Public Service Commission, Docket Nos. 4091-U and 4146-U (1992), on behalf of Amicalola Electric Membership Corporation. 92. PacifiCorp, Inc., before the Federal Energy Regulatory Commission, Docket No. EC88-2-007 (1992), on behalf of Nucor Steei-Uta. 93. South Carolina Pipeline Corporation, before the South Carolina Public Service Commission, Docket No. 90-452-G (1991), on behalf of Nucor Steel-Darlington. 94. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 91-4-E, 1991 Fall Hearing, on behalf of Nucor Steel-Darlington. 95. Sonat, Inc., and North Carolina Natural Gas Corporation, before the North Carolina Utilties Commission, Docket No. G-21, Sub 291 (1991), on behalf ofNucor Corporation, Inc. 96. Northern States Power Company, before the Minnesota Public Utilties Commission, Docket No. E002/GR-91-001 (1991), on behalf of North Star Steel-Minnesota. 10 DENNIS W. GOINS 97. Gulf States Utilties Company, before the Louisiana Public Service Commission, Docket No. U-I7282, Phase iv -Rate Design (1991), on behalf ofthe Deparment of Energy, Strategic Petroleum Reserve. 98. Houston Lighting & Power Company, before the Public Utilty Commission of Texas, Docket No. 9850 (1990), on behalf of the Departent of Energy, Strategic Petroleum Reserve. 99. General Services Administration, before the United States General Accounting Offce, Contract Award Protest (1990), Solicitation No. GS- 00P-AC87-91, Contract No. GS-00D-89-B5D-0032, on behalf of Satila Rural Electric Membership Corporation, re cost of service and rate design. 100. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 90-4-E (1990 Fall Hearing), on behalf of Nucor Steel-Darlington, re fuel-cost recovery. 101. Gulf States Utilities Company, before the Louisiana Public Service Commission, Docket No. U-I7282, Phase II-Rate Design (1990), on behalf of the Department of Energy, Strategic Petroleum Reserve, re cost of service and rate design. 102. Atlanta Gas Light Company, before the Georgia Public Service Commission, Docket No. 3923-U (1990), on behalf of Herbert G. Burris and Oglethorpe Power Corporation, re anticompetitive pricing schemes. 103. Ohio Edison Company, before the Ohio Public Utilities Commission, Case No. 89-1001-EL-AIR (1990), on behalf of North Sta Steel-Ohio, re cost of service and rate design. 104. Gulf States Utilities Company, before the Louisiana Public Service Commission, Docket No. U-I7282, Phase II-Cost of Service!Revenue Spread (1989), on behalf of the Deparment of Energy, Strategic .Petroleum Reserve. 105. Northern States Power Company, before the Minnesota Public Utilities Commission, Docket No. E002/GR-89-865 (1989), on behalf of North Star Steel-Minnesota. 106. Gulf States Utilties Company, before the Louisiana Public Service Commission, Docket No. U-I7282, Phase II-Rate Design (1989), on behalf of the Deparment of Energy, Strategic Petroleum Reserve. 107. Utah Power & Light Company, before the Utah Public Service Commission, Case No. 89-039-10 (1989), on behalf of Nucor Steel-Utah and Vulcraft, a division ofNucor Steel. 11 DENNS W. GOINS 108. Soyland Power Cooperative, Inc. v. Central Ilinois Public Service Company, Docket No. EL89-30-000 (1989), before the Federal Energy Regulatory Commission, on behalf of Soyland Power Cooperative, Inc., re wholesale contract pricing provisions 109. Gulf States Utilties Company, before the Public Utilty Commission of Texas, Docket No. 8702 (1989), on behalf of the Deparent of Energy, Strategic Petroleum Reserve. 110. Houston Lighting and Power Company, before the Public Utilty Commission of Texas, Docket No. 8425 (1989), on behalf of the Department of Energy, Strategic Petroleum Reserve. 111. Northern Ilinois Gas Company, before the Ilinois Commerce Commission, Docket No. 88-0277 (1989), on behalf of the Coalition for Fair and Equitable Transportation, re retail gas transportation rates. 112. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 79-7-E, 1988 Fall Hearing, on behalf of Nucor Steel-Darlington, re fuel-cost recovery. 113. Potomac Electric Power Company, before the District of Columbia Public Service Commission, Formal Case No. 869 (1988), on behalf of Peoples Drug Stores, Inc., re cost of service and rate design. 114. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 88-11-E (1988), on behalf of Nucor Steel- Darlington. 115. Northern States Power Company, before the Minnesota Public Utilties Commission, Docket No. E-002/GR-87-670 (1988), on behalf of the Metalcasters of Minnesota. 116. Ohio Edison Company, before the Ohio Public Utilties Commission, Case No. 87-689-EL-AIR (1987), on behalf of North Star Steel-Ohio. 117. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 87-7-E (1987), on behalf of Nucor Steel- Darlington. 118. Gulf States Utilities Company, before the Louisiana Public Service Commission, Docket No. U-17282, Phase I (1987), on behalf of the Strategic Petroleum Reserve. 119. Gulf States Utilties Company, before the Public Utilty Commission of Texas, Docket No. 7195 (1987), on behalf of the Strategic Petroleum Reserve. 12 DENNIS W. GOINS 120. Gulf States Utilties Company, before the Federal Energy Regulatory Commission, Docket No. ER86-558-006 (1987), on behalf of Sam Rayburn G&T Cooperative. 121. Utah Power & Light Company, before the Utah Public Service Commission, Case No. 85-035-06 (1986), on behalf of the U.S. Air Force. 122. Houston Lighting & Power Company, before the 'Public Utilty Commission of Texas, Docket No. 6765 (1986), on behalf of the Strategic Petroleum Reserve. 123. Central Maine Power Company, before the Maine Public Utilties Commission, Docket No. 85-212 (1986), on behalfofthe U.S. Air Force. 124. Gulf States Utilties Company, before the Public, Utilty Commission of Texas, Docket Nos. 6477 and 6525 (1985), on behalf of North Sta Steel- Texas. 125. Ohio Edison Company, before the Ohio Public Utilties Commission, Docket No. 84-1359-EL-AIR (1985), on behalf of North Star Steel-Ohio. 126. Utah Power & Light Company, before the Utah Public Service Commission, Case No. 84-035-01 (1985), on behalf ofthe U.S. Air Force. 127. Central Vermont Public Service Corporation, before the Vermont Public Service Board, Docket No. 4782 (1984), on behalf of Central Vermont Public Service Corporation. 128. Gulf States Utilities Company, before the Louisiana Public Service Commission, Docket No. U-15641 (1983), on behalf of the Strategic Petroleum Reserve. 129. Southwestern Power Administration, before the Federal Energy Regulatory Commission, Rate Order SWPA-9 (1982), on behalf of the Departent of Defense. 130. Public Service Company of Oklahoma, before the Federal Energy Regulatory Commission, Docket Nos. ER82-80-000 and ER82-389-000 (1982), on behalf of the Departent of Defense. 131. Central Maine Power Company, before the Maine Public Utilities Commission, Docket No. 80-66 (1981), on behalf of the Commission Staff. 132. Bangor Hydro-Electric Company, before the Maine Public Utilities Commission, Docket No. 80-108 (1981), on behalf of the Commission Staff. 133. Oklahoma Gas & Electric, before the Oklahoma Corporation Commission, Docket No. 27275 (1981), on behalf of the Commission Staff. 13 DENNS W. GOINS 134. Green Mountain Power, before the Vermont Public Service Board, Docket No. 4418 (1980), on behalf of the PSB Staff. 135. Wiliams Pipe Line, before the Federal Energy Regulatory Commission, Docket No. OR79-1 (1979), on behalfofMapco, Inc. 136. Boston Edison Company, before the Massachusetts Departent of Public Utilties, Docket No. 19494 (1978), on behalf of Boston Edison Company. 137. Duke Power Company, before the North Carolina Utilities Commission, Docket No. E-7, Sub 173, on behalf ofthe Commission Staff. 138. Duke Power Company, before the North Carolina Utilties Commission, Docket No. E-l 00, Sub 32, on behalf of the Commission Staff. 139. Virginia Electric & Power Company, before the North Carolina Utilities Commission, Docket No. E-22, Sub 203, on behalf of the Commission Staff. 140. Virginia Electric & Power Company, before the North Carolina Utilities Commission, Docket No. E-22, Sub 170, on behalf of the Commission Staff. 141. Southern Bell Telephone Company, before the North Carolina Utilties Commission, Docket No. P-5, Sub 48, on behalf of the Commission Staff. 142. Western Carolina Telephone Company, before the North Carolina Utilities Commission, Docket No. P-58, Sub 93, on behalf ofthe Commission Staff. 143. Natural Gas Ratemaking, before the North Carolina Utilties Commission, Docket No. G-lOO, Sub 29, on behalf of the Commission Staff. 144. General Telephone Company of the Southeast, before the North Carolina Utilities Commission, Docket No. P-19, Sub 163, on behalf of the Commission Staff. 145. Carolina Power and Light Company, before the North Carolina Utilities Commission, Docket No. E-2, Sub 264, on behalf ofthe Commission Staff. 146. Carolina Power and Light Company, before the North Carolina Utilties Commission, Docket No. E-2, Sub 297, on behalf of the Commission Staff. 147. Duke Power Company, et al., Investigation of Peak-Load Pricing, before the North Carolina Utilities Commission, Docket No. E-I00, Sub 21, on behalf of the Commission Staff. 148. Investigation of Intrastate Long Distance Rates, before the North Carolina Utilities Commission, Docket No. P-I00, Sub 45, on behalf of the Commission Staff. 14