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Home My WebLink About200705302007 IRP Appendices.pdfPAC-O7- PacifiCorp 2007 IRP Table of Contents TABLE OF CONTENTS Table of Contents """"""""""""""""""""""""""'".........................,................................................... Index of Tables .... ........ .................................... ....... ..... ............. ............. ..... .... ..... ......... ..................... .... iv Index of Figures............................................. ......................................................................................... v Appendix A - Base Assumptions ............................................................................................................... General Assumptions ............................................................................................................................. Study Period .....................................................................................................,................................ Inflation Curve................................................................................................................................... Planning Reserve Margin .... .......... ......"........... ........ ...... ............... ........... ........... ............. ......... ........ Load Forecast ......................................................................................................................................... State Summaries ................................................................................................................................ Oregon """""""""""""""""""""""""""""................................................................................ Washington................................................................................................................................... California...................................................................................................................................... Utah """""""""""""""""""""""""""........................................................................................ Idaho ............................................................................................................................................. Wyoming ...................................................................................................................................... Class 2 DSM...................................................................................................................................... Near Term Customer Class Sales Forecast Methods......................................................................... 6 Residential, Commercial, Public Street and Highway Lighting, and Irrigation Customers ......... Industrial Sales and Other Sales to Public Authorities ................................................................. 7 Long Term Customer Class Sales Forecast Methods ........................................................................ 7 Economic and Demographic Sector ............................................................................................. 7 Residential Sector ......................................................................................................................... Commercial Sector ....................................................................................................................... Industrial Sector......................................................,................................................................... Other Sales.................................................................................................................................. Merging ofthe Near-Term and Long-Term Sales Forecasts........................................................... 10 Total Load Forecasting Methods.........................................................................................,........... System Load Forecasts """""""""""""""""""""""""""................................................,........ Hourly Load Forecasts......................................................................................................"........ System Peak Forecasts................................................................................................................ Treatment of State Economic Development Policies ................................................................. Elasticity Studies .........................................................".................................................................. 12 Total Class Analysis ................................................................................................................... 12 Analysis of Customers Who Called About Their Bills............................................................... 12 Sub-group Analysis """"""""""""""""""""" ............... ............................ .......................... ..... Commodity Prices ................................................................................................................................ Market Fundamental Forecasts........................................................................................................ Gas Price Forecasts...... ......................................................... ......... ......... ...... ........ ....... ....... ............. 16 Wholesale Electricity Price Forecasts............................................................................................. 17 Post-2020 real growth rate sensitivity analysis .......................................................................... Regional transmission project impact analysis.. .............. .................... ............ ............... ............ 18 Coal Prices....................................................................................................................................... Coal Prices - West Side I GCC ................................................................................................... 19 Emission Costs """"""""""""""""""""""""""".................................,............................................. Carbon Dioxide. ........ ...................... .............................. ................. ........................ ......................... 20 Sulfur Dioxide ......... .................. ......... ............. ................. ......... ....... ........... ......................... ........... 20 Nitrogen Oxides............................................................................................................................... PacifiCorp 2007 IRP Table of Contents Mercury ........................................................................................................................................... Renewable Assumptions ...................................................................................................................... Production Tax Credit ..................................................................................................................... Renewable Energy Credits .............................................................................................................. Existing Resources ............................................................................................................................... Hydroelectric Generation ............................................................:................................................... 22 Hydroelectric Relicensing Impacts on Generation ..................................................................... 23 Generation Resources ...................................................................................................................... Demand-Side Management ............................................................................................................. 26 Class 1 Demand-Side Management ...... ...................... ............................... ..... ....... ...... ............... Class 2 Demand-Side Management............................................................................................ Class 3 Demand-Side Management.. ..... .................. .............................. ...... ....... ..... ................... Class 4 Demand-Side Management.......... .................................................................................. 30 Transmission System....................................................................................................................... Topology ..................................................................................................................................... Losses ...............................................................................,......................................................... Congestion Charges .................................................................................................................... Appendix B - Demand Side Management Proxy Supply Curve Report ............................................. Appendix C - Detailed CEM Modeling Results ..................................................................................... 99 Alternative Future and Sensitivity analysis Scenario Results .............................................................. Additional CEM Sensitivity Analysis Scenario Results..................................................................... 107 Appendix D - Supplementary Portfolio Information ..........................................................................117 Carbon Dioxide Emissions................................................................................................................. 117 Portfolio PVRR Cost Component Comparison ........ .............................................................. ............ 121 Appendix E - Stochastic Risk Analysis Methodology .........................................................................125 Overview ............................................................................................................................................125 Stochastic Variables ...........................................................................................................................125 The PaR Stochastic Model............................................................................................................ 125 Stochastic Output .............,................................................................................................................. 126 Appendix F - Public Input Process .......................................................................................................133 Participant List ...........................................................................,.......................................................133 Commissions .................................................................................................................................133 Intervenors.....................................................................................................................................133 Others ...............................,............................................................................................................134 Public Input Meetings........... ..... ................... ......... ...................... ...... ........ ............... ..... .................... 134 2005 Public Process....... ............ ............ .................... ............. ................... .................................... 135 May 18 2005 - General Meeting.............................................................................................135 August 3 2005 - General Meeting...........................................................................................135 October 5 , 2005 - General Meeting......................................................................................... 135 2006 Public Process...... ............... ......... ..... ......... ............ ......." ...... ......... ....................................... 136 December 7, 2005 - General Meeting...................................................................................... 13 January 13 2006 - Renewables Workshop.............................................................................. 136 January 24, 2006 - Load Forecasting Workshop ............."...................................................... 136 February 10 2006 - Demand-Side Management Workshop ................................................... 137 April 20, 2006 - General Meeting............................................................................................137 May 10, 2006 - General Meeting............................................................................................. 13 June 7, 2006 - General Meeting...............................................................................................137 August 23 2006 - General Meeting......................................................................................... 13 October 31 2006 - General Meeting .......................................................................................138 PacifiCorp 2007 IRP Table of Contents 2007 Public Process.......................................................................................................................138 February 1 2007 - General Meeting........................................................................................ 13 8 April 18, 2007 - General Meeting............................................................................................138 Parking Lot Issues .............................................................................................................................. 138 Public Review ofIRP Draft Document..............................................................................................139 Portfolio Optimality.......................................................................................................................139 Planning Reserve Margin Selection and Resource Needs Assessment.........................................141 Relationship ofPacifiCorp s IRP with its Business Plan ..............................................................141 The 2007 IRP Action Plan.............................................................................................................142 Demand-Side Management ...........................................................................................................142 Market Reliance, Availability, and Price Risk ..............................................................................143 Scope of Resource Analysis......... ...... ........... ...... ....... ..... ........ .............. ............ ........ .................... 143 Load Forecast ................................................................................................................................145 Carbon Dioxide Regulatory Risk Analysis ...................................................................................146 Transmission..................................................................................................................................146 Miscellaneous ................................................................................................................................147 Contact Information ........................,..................................................................................................148 Appendix G - Performance on 2004 IRP Action Plan......................................................................... 149 Introduction ........................................................................................................................................149 Appendix H - Deferral of Distribution Infrastructure with Customer-Based Combined Heat and Power Gen era tio n ........ ........................... ......................... ................. ........ ...... .............. 155 Introduction ........................................................................................................................................155 Traditional Connection.......................................................................................................................155 Generation Connection.............................................""""""""""""""""""""""""""'"...................155 Conclusion..........................................................................................................................................156 Appendix I - IRP Regulatory Compliance ...........................................................................................157 Background ........................................................................................................................................157 General Compliance """"""""""""""""""""""""""".....................................................................157 California.............................................."""""""""""""""""""""""""""...................................159 Idaho..............................................................................................................................................159 Oregon...........................................................................................................................................159 Utah .......................................................................................,.......................................................159 Washington....................................................................................................................................160 Wyoming .......................................................................................................................................160 Appendix J - Wind Resource Methodology .........................................................................................189 Wind Integration Costs.......................................................................................................................189 Incremental Reserve Requirements ......................................."......................................................189 System Balancing Costs ................................................................................................................193 Determination of Cost-Effective Wind Resources .............................................................................195 Wind Capacity Planning Contribution...... ..... ........ .......................... ..... .................................. ........... 197 Regional Studies.................................................................................................................................199 Effect of Resource Addition Fuel Type on the Company s Cost to Integrate Wind Resources ........ 200 iii PacifiCorp 2007 IRP Index of Tables and Figures INDEX OFT ABLES Table A.l - Inflation..................................................................................................................................... Table A.2 - Historical and Forecasted Sales Growth in Oregon .................................................................. Table A.3 - Historical and Forecasted Sales Growth in Washington ....................... ............ ........................ 2 Table A.4 - Historical and Forecasted Sales Growth in California.............................................................. 3 Table A.5 - Historical and Forecasted Sales Growth in Utah ...................................................................... 3 Table A.6 - Historical and Forecasted Sales Growth in Idaho ..................................................................... 4 Table A.7 - Historical and Forecasted Sales Growth in Wyoming .............................................................. 5 Table A.8 - Class 2 DSM Included in the System Load Forecast................................................................ 6 Table A.9 - CO2 cost adders used for Scenario Analysis ........................................................................... 20 Table A.l 0 - Hydroelectric Generation Facilities...................................................................................... 23 Table A.ll - Estimated Impact ofFERC License Renewals on Hydroelectric Generation....................... 23 Table A.12 - Thermal and Renewable Generation Facilities ..................................................................... Table A.13 - Class 1 Demand-Side Management Programs ...................................................................... 26 Table A.14 - Class 2 Demand-Side Management programs ...................................................................... 27 Table A.15 - Class 2 Demand-Side Management Service Area Totals - All States, All Programs........... 28 Table A.16 - Class 3 Demand-Side Management Programs ...................................................................... 29 Table A.17 - Class 4 Demand-Side Management Programs ...................................................................... 30 Table c.l - Alternative Future Scenarios................................................................................................... 99 Table C.2 - Sensitivity Analysis Scenarios ................................................................................................ 99 Table C.3 - Aggregate Resource Additions.... ........... ....... .............. ............................. ................... .......... 100 Table C.4 - Wind Resource Additions .....................................................................................................101 Table C.5 - Front Office Transactions...................................................................................................... l02 Table C.6 - Gas Additions, Including Combined Heat & Power .............................................................103 Table C. 7 - IGCC Additions.................................................................................................................... 104 Table c.8 - Pulverized Coal Additions ....................,...............................................................................105 Table C.9 - Demand Side Management Additions................................................................................. 106 Table c.1O - Additional Sensitivity Scenarios for CEM Optimization.................................................... 107 Table C.l1 - Present Value of Revenue Requirements Comparison ($ Billion)...................................... 108 Table C.12 - Total Resources Accrued by 2016 (Megawatts) .................................................................108 Table c.13 - Wind Resources Accrued by 2016 (Nameplate Megawatts)............................................... 108 Table C.14 - Gas Resources Accrued by 2016 (Megawatts).................................................................... 109 Table c.15 - Pulverized Coal Resources Accrued by 2016 (Megawatts) ................................................109 Table C.l6 - IGCC Resources Accrued by 2016 (Megawatts) ................................................................109 Table C.17 - CEM Results: Aggregate Resource Additions ................................................... ................ 110 Table C.18 - CEM Results: Wind Resource Additions........................................................................... III Table C.19 - CEM Results: Front Office Transactions ...........................................................................112 Table C.20 - CEM Results: Gas Additions, Including Combined Heat and Power ................................ 113 Table C.21 - CEM Results: IGCC Additions ..........................................................................................lI4 Table C.22 - CEM Results: Pulverized Coal Additions ....... ......... .................... ........ ............ ............. ..... 115 Table C.23 - CEM Results: Demand-side Management Additions ........................................................116 Table D.l - CO2 Emissions Attributable to Retail Sales by State ............................................................117 Table D.2 - Unit Emission Costs for Group 2 Risk Analysis Portfolio Resources, 2016........................ 118 Table D.3 - Group 1: Portfolio PVRR Cost Components (Cap-and-Trade Strategy) ..............................121 Table D.4 - Group 2: Portfolio PVRR Cost Components (CO2 Cap-and- Trade Compliance Strategy).. 123 Table D.5 - Group 2: Portfolio PVRR Cost Components (CO2 Tax Compliance Strategy) ....................124 Table G.l- Status Update on 2004 IRP Action Plan ...............................................................................150 Table I.1 - Integrated Resource Planning Standards and Guidelines Summary by State.........................l61 Table 1.2 - Handling of 2004 IRP Acknowledgement and Other IRP Requirements ........ :..................... 164 PacifiCorp 2007 IRP Index of Tables and Figures Table 1.3 - Oregon Public Utility Commission IRP Standard and Guidelines .........................................172 Table I.4 - Utah Public Service Commission IRP Standard and Guidelines............................................ 181 Table J.l - Incremental Capacity Contributions from Proxy Wind Resources ........................................198 Table J.2 - Wind Integration Costs from Northwest Utility Studies .......................................................199 INDEXORFIGURES Figure A.l- Natural Gas and Wholesale Electric Price Curve Components............................................. 16 Figure A.2 - Natural Gas Price Curve ...................................................................................................... Figure A.3 - Wholesale Electricity Price Forecast - Heavy Load Hours / Light Load Hours ................... 17 Figure A.4 - Average Annual Coal Prices for Resource Additions ........................................................... Figure A.S - Sulfur-Dioxide (SO2) Spot Price F orecast........... .................................................................. Figure A.6 - IRP Transmission System Topology..................................................................................... 31 Figure D.l - Annual CO2 Intensity, 2007-2016 ($8 CO2 Adder Case) ....................................................119 Figure D.2 - Annual CO2 Intensity, 2007-2016 ($61 CO2 Adder Case) ..................................................120 Figure E.l - 2007 Frequency of Eastern (Palo Verde) Electricity Market Prices - 100 Iterations .......... 126 Figure E.2 - 2016 Frequency of Eastern (Palo Verde) Electricity Market Prices - 100 Iterations ..........127 Figure E.3 - 2007 Frequency of Western (Mid C) Electricity Market Prices - 100 Iterations ................ 127 Figure E.4 - 2016 Frequency of Western (Mid C) Electricity Market Prices - 100 Iterations ................127 Figure E.S - 2007 Frequency of Eastern Natural Gas Market Prices - 100 Iterations .............................128 Figure E.6 - 2016 Frequency of Eastern Natural Gas Market Prices - 100 Iterations .............................128 Figure E.7 - 2007 Frequency of Western Natural Gas Market Prices - 100 Iterations............................ 128 Figure E.8 - 2016 Frequency of Western Natural Gas Market Prices - lOO Iterations............................ 129 Figure E.9 - Goshen Loads....................................................................................................................... 129 Figure E.I0 - Utah Loads .........................................................................................................................130 Figure E.l1 - Washington Loads..............................................................................................................130 Figure E.12 - West Main (California and Oregon) Loads........................................................................ 131 Figure E.13 - Wyoming Loads ................................................................................................................. 131 Figure E.14 - 2007 Hydroelectric Generation Percentile .........................................................................132 Figure E.15 - 2016 Hydroelectric Generation Percentile .........................................................................132 Figure J.l - Load Following Reserve Requirement Illustration ...............................................................191 Figure J.2 - Load Following Reserve Requirement for Load Net of Wind.............................................. 191 Figure J.3 - Incremental Reserve Cost Associated with Various Wind Capacity Amounts..................... 192 Figure J.4 - Operating Cost ofIncremental Load Following Reserves .................................................... 193 Figure J.S - PacifiCorp System Balancing Cost....................................................................................... 194 Figure J.6 - Renewables Capacity Additions for Alternative Future Scenarios ....................................... 196 Figure J.7 - Cumulative Capacity Contribution of Renewable Additions for the PTC Sensitivity Study 197 PacifiCorp 2007 IRP Index of Tables and Figures PacifiCorp 2007 IRP Appendix A Base Assumptions APPENDIX A - BASE ASSUMPTIONS This appendix will cover the base assumptions used for both the Capacity Expansion Module and the Planning and Risk model used for portfolio analysis in the 2007 Integrated Resource Plan. GENERAL ASSUIVIPTIO Study Period PacifiCorp currently uses a calendar year that begins on January 1 and ends December 31. The study period covers a 20-year period beginning January 1 2007 through December 31 2026. Inflation Curve Where price forecasts and associated escalation rates were not established by external sources IRP simulations and price forecasts were performed with PacifiCorp s inflation rate schedule (See Table A.l below). Unless otherwise stated, prices or values in this appendix are expressed in nominal dollars. Table A.I - Inflation AYerageAnnual Rate 1.86 1.80 1.88 Plannin2 Reserve Mar2in PacifiCorp assumed both 12 and 15 percent planning margin for developing the load and re- source balance. Capacity Expansion Module scenario analysis used 12 percent as the low case 15 percent as the medium case and 18 percent as a high case during the initial phase of analyses. To preserve planning flexibility, the company adopted a reserve margin range of 12 to 15 percent in recognition of uncertainties concerning the cost and reliability impact of evolving state re- source policies to foster renewable energy development and reduce utilities' carbon footprints. LOAD FORECAST This load forecast section provides state-level forecasted retail sales summaries, load forecasting methodologies, and the elasticity studies. Chapter 4 provides the forecast information for each state and the system as a whole by year for 2007 through 2016. State Summaries Oregon Table A.2 summarizes Oregon state forecasted sales growth compared with historical growth by customer class. PacifiCorp 2007 IRP Appendix A Base Assumptions Table A.2 - Historical and Forecasted Sales Growth in Oregon Residential ' Commercial "Industrial"374 4 614 2 957SS4 4 843 3 238 Av~ra eAnnllal Growth Rate0% -S% - The forecast of residential sales is expected to have a slightly slower growth than has been ex- perienced historically. Population growth is expected to continue in the service area, which is driving some of the growth, while usage per customer in the residential class is expected to de- cline slightly due to conservation. Forecasted commercial class sales are projected to grow slightly more slowly over the forecast horizon compared to historical periods. Usage per customer is projected to remain flat due to increased equipment efficiency which offsets increased saturation of air conditioning. Forecasted industrial class sales are projected to decline more slowly over the forecast horizon compared to historical periods. In the later years of this historical period, two large industrial customers chose to leave PacifiCorp s system. This, coupled with declines over the decade in the lumber and wood products industries, resulted in an overall decline in sales to this class. Over the forecast horizon, continuing growth is expected in food processing industries, specialty metals manufacturing industries, and niche lumber and wood businesses, along with continued diversi- fication in the manufacturing base in the state. The factors influencing the forecasted sales growth rates are also influencing the forecasted peak demand growth rates. Washington Table A.3 summarizes Washington state forecasted sales growth compared with historical growth by customer class. Table A.3 - Historical and Forecasted Sales Growth in Washington Residential Commercial IndustrialS87 1 417 I OS4S96 1 41S 990 Avera e Annual GrovvthRate1% 0.1.2% 2.1.1% 1.1% The growth in residential class sales is due to continuing population growth and household for- mation in this part of PacifiCorp s service area. Usage per customer is expected to increase slightly due to increases in both real income and the residential square footage. PacifiCorp 2007 IRP Appendix A - Base Assumptions The continuing residential customer growth also affects the commercial sector through increas- ing numbers of commercial customers. Usage per commercial customer is decreasing during the forecast horizon due to increasing saturations in air-conditioning and office equipment that are being offset by efficiency gains in other end-uses, such as lighting. The industrial class is projected to grow at rates above the historical rate. Industrial production is projected to continue to grow in the food, lumber, and paper industries in the state. There are indications that bio-diesel facilities wiHlocate in the state during the forecast period. California Table A.4 summarizes California state forecasted sales growth compared with historical growth by customer class. Table A.4 - Historical and Forecasted Sales Growth in California " Residential 391 398 Irri ation The rate of growth in residential class sales is driven, in part, by the continuing growth in popu- lation in this part of PacifiCorp s service area. Usage per customer in the residential class is de- clining slightly. Home sizes continue to increase, resulting in more growth in use per customer but this is more than offset by the increasing adoption of efficient appliances. In addition, sum- mer electrical usage increases from air conditioning additions are being somewhat offset by de- clining electric spacing heating saturations and appliance efficiency gains. The continuing population growth also affects sales in the commercial sector through continued commercial customer growth. AdditionaUy, commercial usage per customer is increasing due to greater square footage per building in new construction, increases in the number of offices, and the increasing use of office equipment in aU commercial structures. However, some of this growth is being offset from increased equipment efficiency over the forecast horizon. Declines over the decade in the lumber and wood product industries production resulted in an overall decline in the industrial sales; however, there are indications that this trend has ended and growth in other businesses are expected to continue. U~ Table A.5 summarizes Utah state forecasted sales growth compared with historical growth by customer class. Table A.5 - Historical and Forecasted Sales Growth in Utah 2005 GWh 2006 GWh Residential 707 139 Commercial 776 079 Industrial 944 312 Irri atiOn: Other. Total.ISI S47 20,124171 S2S 21 227 PacifiCorp 2007 IRP Appendix A Base Assumptions Utah continues to see natural population growth that is faster than many of the surrounding states. During the historical period, Utah experienced rapid population growth with a high rate of in-migration. However, the rate of population growth is expected to be lower in the coming dec- ade as in-migration into the state slows. Use per customer in the residential class should continue at current levels for the forecast horizon. One of the reasons for the high usage per customer is that newer homes are assumed to be larger. In addition, it is assumed that air conditioning satura- tion rates for single family and manufactured houses will continue to grow. The relatively high population growth also affects sales in the commercial sector by continued commercial customer growth. Usage per customer is projected to increase with new construction having greater square footage per building and increasing usage of office equipment. However some of this growth is being offset from equipment efficiency gains over the forecast horizon. The industrial class has been experiencing significant industrial diversification in the state and win continue to cause sales growth in the sector. Utah has a strategic location in the western half of the United States, which provides easy access into many regional markets. The industrial base has become more linked to the region and is less dependent on the natural resource base within the state. This provides a strong foundation for continued growth into the future. The peak demand for the state of Utah is expected to have a high growth rate during the forecast period. This is due to several factors: first, newer residential structures are assumed to be larger; second, the air conditioning saturation rates in the state continue to increase in the residential and commercial sectors; and third, newly constructed commercial structures are assumed to be larger than during historical periods. Idaho Table A.6 summarizes Idaho state forecasted sales growth compared with historical growth by customer class. Table A.6 - Historical and Forecasted Sales Growth in Idaho Residential Commercial Industrial Irri!!ation I Other Total 2005 GWh 652 382 650 . 534 221 2006 GWh 678 401 659 592 332 Avera2e Annual Growth Rate 1995-3.2% 2007-2.2%1.2%1.0% The growth of sales in the residential sales class continues to be strong in the forecast horizon due to customer growth and increased usage per customer. The customer growth is driven by strong net in-migration and household formation. The increased usage per customer is driven by PacifiCorp 2007 IRP Appendix A Base Assumptions larger home size and a relatively large number of people per household. It is also assumed that air conditioning saturation rates will continue to be increasing during the forecast horizon. The growth rate for commercial class sales is expected to be less than historic levels but will continue to be strong due to customer growth in response to the increasing residential customer growth and due to an increase in the number of offices. Usage per customer is projected to in- crease, which has been influenced in part by new construction at the Brigham Young University Idaho campus, increased air conditioning saturation, office equipment, and exterior lighting. However, this growth is somewhat offset by equipment efficiency gains over the forecast hori- zon. Industrial sales are assumed to be near maximum levels of production and remain there during the forecast horizon. Wyoming Table A.7 summarizes Wyoming state forecasted sales growth compared with historical growth by customer class. Table 7 - Historical and Forecasted Sales Growth in Wyoming Residential Commercial Industrial Irri ation939 1 290 5 756 970 1 367 5 939 eAnnualGrowth Rate5% 1.2%6% 6. The residential sales forecast is expected to continue to grow at nearly historical rates. Popula- tion growth is expected to continue in the service area, which causes some of the growth. Home sizes continue to increase, resulting in increased general use per customer. Increasing air condi- tioning saturations are resulting in more use per customer during the summer months. Commercial sales are projected to grow at a similar rate over the forecast horizon compared to historical periods due to customer growth and increasing usage per customer. Customer growth occurs in response to residential customer growth and the growth of the office sector. Usage per customer is projected to increase for the forecast period due to increases of office and misceUa- neous equipment. A major change in the Wyoming sales forecast occurs in the industrial sales sector. Large gas extraction customers are expected to locate in the PacifiCorp service area. The location of these industrial customers in the service area also contributes to the growth in the residential and commercial customer sectors. Class 2 DSM Identified and budgeted Class 2 DSM programs have been included in the load forecast as a dec- rement to the load. By 2016, there are 143 MWa of Class 2 programs in the forecast. This sav- ings includes 10 MWa to be implemented by the Energy Trust of Oregon within PacifiCorp service territory. Table A.8 shows average program savings and peak obligation hour savings by PacifiCorp 2007 IRP Appendix A Base Assumptions year. In 2016, these Class 2 programs reduce peak system load from what it otherwise would have been by 2.2%. Table A.8 - Class 2 DSM Included in the System Load Forecast 2007 2008 2009 2010 20H 2012.201j .2014, '201519 38 54 62 75 87 100 112 124 163 185 206 227 217 Near Term Customer Class Sales Forecast Methods Residential, Commercial, Public Street and Highway Lighting, and Irrigation Customers Sales to residential, commercial, public street and highway lighting, and irrigation customers are developed by forecasting both the number of customers and the use per customer in each class. The forecast of kWh sales for each customer class is the product of two separate forecasts: num- ber of customers and use per customer. The forecast of the number of customers relies on weighted exponential smoothing statistical techniques formulated on a twelve-month moving average of the historical number of customers. For each customer class the dependent variable is the twelve-month moving average of custom- ers. The exponential smoothing equation for each case is in the following form: St = W Xt + (l-w) * St- S/2) = St *Xt + (l-w) * St- (2) S/3) = St(2) *Xt + (l-w) * St- (3) where Xt is the twelve-month moving average of customers. The form of this forecasting equa- tion is known as a triple-exponential smoothing forecast model and, as derived from these equa- tions, most of the weight is applied to the more recent historical observations. By applying addi- tional weight to more current data and utilizing exponential smoothing, the transition from actual data to forecast periods is as smooth as possible. This technique also ensures that the December to January change from year to year is reflective of the same linear pattern. These forecasts are produced at the class level for each of the states in which PacifiCorp has retail service territory. PacifiCorp believes that the recent past is most reflective of the near future. Using weights ap- plies greater importance to the recent historical periods than the more distant historical periods and improves the reliability of the final forecast. PacifiCorp 2007 IRP Appendix A Base Assumptions The average use per customer for these classes is calculated using regression analysis on the his- torical average use per customer, which determines if there is any material change in the trend over time. The regression equation is of the form KPCt = a + b*t where KPC is the annual kilowatt-hours per customer and "t" is a time trend variable having a value of zero in 1992 with increasing increments of one thereafter. "" and "b" are the estimated intercept and slope coefficients, respectively, for the particular customer class. As in the forecast of number of customers, the forecasts of kilowatt-hours per customer are reviewed for reason- ableness and adjusted if needed. The forecast of the number of customers is multiplied by the forecast of the average use per customer to produce annual forecasts of energy sales for each of the four classes of service. Industrial Sales and Other Sales to Public Authorities These classes are diverse. In the industrial class, there is no typical customer. Large customers have differing usage patterns and sizes. It is not unusual for the entire class to be strongly influ- enced by the behavior of one customer or a sman group of customers. In order to forecast cus- tomer loads for industrial and other sales to public authorities, these customers are first classified based on their Standard Industrial Classification (SIC) codes, which are numerical codes that represent different types of businesses. Customers are further separated into large electricity users and smaner electricity users. PacifiCorp s forecasting staff, which consults with each PacitiCorp customer account manager assigned to each of the large electricity users, makes esti- mates of that customer s projected energy consumption. The account managers maintain direct contact with the large customers and are therefore in the best position to know whether any plans or changes in their business processes may impact their energy consumption. In addition, the forecasting staff reviews industry trends and monitors the activities of the customers in SIC code groupings that account for the bulk of the industry sales. The forecasting staff then develops sales forecasts for each SIC code group and aggregates them to produce a forecast for each class. Lont! Term Customer Class Sales Forecast Methods Economic and demographic assumptions are key factors influencing the forecasts of electricity sales. Absent other changes, demand for electricity win paranel other regional and national eco- nomic activities. However, several influences can change that paranel relationship; for example changes in the price of electricity, the price and availability of competing fuels, changes in the composition of economic activity, the level of conservation, and the replacement rates for build- ings and energy-using appliances. The long-term forecast considers an of these as variables. The tiJllowing is a generalized discussion of the methodology implemented for the long-term forecast. The forecast is derived from a consistent set of economic, demographic and price pro- jections specific to each of the six states served by PacifiCorp. Forecasts of employment, popula- tion and income with a consistent view of the western half of the United States are used as inputs to the forecasting models. Economic and Demographic Sector Employment serves as the major determinant of future trends among the economic and demo- graphic variables used to "drive" the long-term sales forecasting equations. PacifiCorp s meth- PacifiCorp 2007 IRP Appendix A Base Assumptions odology assumes that the local economy is comprised of two distinct sectors: basic and non- basic, as presented in "regional export base theory. 1 . The basic sector is comprised of those industries that are involved in the production of goods destined for sales outside the local area and whose market demand is primarily determined at the national level. PacifiCorp calculates a region s share of the employment for these specific indus- tries based on national forecasts of employment for the industries. The non-basic sector theoretically represents those businesses whose output serves the local market and whose market demand is determined by the basic employment and output in the local economy. This simplistic definition of industries as basic or non-basic does not directly confront the prob- lem that much commercial employment (traditionally treated as non-basic) has assumed a more basic nature. This problem is overcome by including other appropriate additional national vari- ables, such as real gross national product in the modeling. In addition, forecasts for county and' state populations are also employed as forecast drivers. From these, service territory level popu- lation forecasts are developed and used. Two primary measures of income are used in producing the forecast of total electricity sales. Total personal income is used as a measure of economic vitality which impacts energy utilization in the commercial sector. Real per capita income is used as a measure of purchasing power which impacts energy choice in the residential sector. PacifiCorp s forecasting system projects total personal income on a service territory basis. Residential Sector For the first time PacifiCorp implemented the end-use software package Residential End-Use Energy Planning System (REEPS) to produce the long-term residential sales forecast. This resi- dential end-use forecasting model has been developed to forecast specific uses of electricity in the customer s home. The model explicitly considers factors such as persons per household, fuel prices, per capita income, housing structure types, and other variables that influence residential customer demand for electricity. Residential energy usage is projected on the basis of 14 end- uses. These uses are space heating, water heating, electric ranges, dishwashers, electric dryers first refrigerators, second refrigerators, lighting, air conditioning, freezers, microwave ovens electric clothes washers, color televisions and residual uses. Air conditioning can be either cen- tral, window or evaporative (swamp coolers). For each 'end-use and structure type, PacifiCorp looks first at saturation levels (the number of customers equipped for that end-use) and how they may change in response to demographic and economic changes. PacifiCorp then looks at penetration levels (how many households are ex- pected to adopt that end-use in the future), given the economic and demographic assumptions. addition, the number of houses that currently have the end-use will be removed upon demolition of the structure. Some appliances may be replaced several times before a home is removed. The 1 The regional export base theory contends that regional economies are dependent on industries that export outside of the region. These industries, and the ones that support them, are the industries that are the major job creators of the region. PacifiCorp 2007 IRP Appendix A Base Assumptions life expectancy of various appliances compared to the life expectancy of a home is considered in the forecasting process. It is also possible that for a particular appliance more than one exists within a household. For certain appliances, such as air conditioning, the saturation rate has been adjusted to account for this occurrence. For other appliances, such as lighting, the saturation rate is assumed to be one, and the usage per appliance for the average household is adjusted to ac- count for more than one light fixture in the house. In this case the average usage per appliance represents the lighting electrical usage in the average household. The basic structure of the end-use model is to multiply the forecast appliance saturation by the appropriate housing stock, which is then multiplied by the annual average electricity use per ap- pliance. Consumption= Housing Stock k, X Saturation of Appliance ik X Electricity Usage of Appliance ik where:i= appliance type k=housing type Annual average electricity use per appliance for each structure type is either estimated by using a conditional demand analysis or it is based upon general1y accepted institutional, industry and engineering standards. Within REEPS , PacifiCorp models three structure types within two age categories, new and ex- isting, because consumption patterns vary with dwel1ing type as wel1 as with age. Therefore new and existing homes are separated further into single family, multi-family and manufactured home dwelling types. REEPS al1ows PacifiCorp to calculate the number of residential customers within each of the new and existing customer categories. These customers are then distributed between the various structure types and sizes. End uses are forecasted for each structure and customer category and these are multiplied by the annual consumption level for each end use. Summing the results gives the total residential sales. Commercial Sector For the first time PacifiCorp implemented the end-use software package Commercial End-Use Energy Planning System (COMMEND) to produce the long-term commercial sales forecast. It forecasts electricity in the same fashion as the REEPS model but uses energy use per square foot for ten end-uses among ten commercial building types. Consumption= Square foot k, X Saturation of Appliance ik X Electricity Usage of Appliance ik where:i = Appliance Type k = Commercial Activity Type The nine end-uses are space heating, water heating, space cooling, ventilation, refrigeration, inte- rior lighting, exterior lighting, cooking, office equipment and miscel1aneous uses. PacifiCorp 2007 IRP Appendix A Base Assumptions Ten building types are modeled: offices, restaurants, retail, grocery stores, warehouses, colleges schools, health, lodging, and miscellaneous buildings. Individual forecasts for each building type are totaled for an overall commercial sector forecast. Industrial Sector PacifiCorp s industrial sector is somewhat dominated by a small number of firms or industries. The heterogeneous mix of customers and industries, combined with their widely divergent char- acteristics of electricity consumption indicates that a substantial amount of disaggregation is re- quired when developing a proper forecasting model for this sector. Accordingly, the industrial sector has been heavily disaggregated within the manufacturing and mining customer segments. The manufacturing sector is broken down into ten categories based on the Standard Industrial Classification code system. These are: food processing (SIC 20), lumber and wood products (SIC 24). paper and allied products (SIC 26), chemicals and allied products (SIC 28), petroleum refining (SIC 29), stone, clay and glass (SIC 32), primary metals (SIC 33), electrical machinery (SlC 36) and transportation equipment (SIC 37). A residual manufacturing category, composed of all remaining manufacturing SIC codes, is also forecasted. The mining industry, located primarily in Wyoming and Utah, has been disaggregated into at least four categories. Separate forecast are performed for the following industries: metal mining (SlC lO). coal mining (SIC 12), oil and natural gas exploration, pumping and transportation (SIC 13). non-metallic mineral mining (SIC 14); there also exists an "other" mining category in some states. The industrial sector is modeled using an econometric forecasting system. Other Sales The other sectors to which electricity sales are made are irrigation, street and highway lighting, interdepartmental and other sales to public authorities. Electricity sales to these smaller customer categories are either forecasted using econometric equations or are held constant at their historic sales levels. Mer!!in1! of the Near-Term and Lon2- Term Sales Forecasts The near-ternl forecast has a horizon of at most three years while the long-term forecast has a horizon of approximately twenty years. Each forecast uses different methodologies, which model the influential conditions for that time horizon. When the forecast of usage for a customer class din~rs between the near-term and the long-term, judgments and mathematical techniques are implemented in the last year of the near-term forecast which converges these values to the long-term forecast. Total Load Forecastin2 Methods System Load Forecasts The sales forecasts by customer class previously discussed measure sales at the customer meter. In order to measure the total projected load that PacifiCorp is obligated to serve, line losses must be added to the sales forecast. The state sales forecasts are increased by estimates for system line PacifiCorp 2007 IRP Appendix A Base Assumptions losses. Line loss percentages vary by type of service and represent the additional electricity re- quirements to move the electricity from the generating plant to each end-use customer. This increase creates the total system load forecast on an annual basis. This annual forecast is further distributed to an hourly load forecast so that the peak hour demand forecast is determined. Hourly Load Forecasts To distribute the loads across time, PacifiCorp has developed a regression based tool that models historical hourly load against several independent variables at the state level. These models have a large number of independent variables. Many of these represent spatial conditions over the year, such as the time of day, the week of the year or day of the week. Additionally, the model uses hourly temperatures for weather stations where the bulk of the load in the state resides. variable representing the humidity levels in the state is also used. Forecasts of the many independent variables are used with these models to create forecasts hourly loads relative to the many different factors. For the spatial variables, the date and time in the future is used. Typically, the load on a weekend is lower than on a weekday because indus- trial and some commercial customers use less electricity. Therefore, a variable used to identify a weekend would have a lower contribution to the forecasted load than a weekday variable; using the calendar date for a future period identifies these spatial conditions. For the weather values the models use the equivalent of the 30-year average temperature for the weather stations at the appropriate day and time in the future. This is also what is used for the humidity measure. A review of the forecasted growth of the hourly load over time against historical growth rates is made to ensure that the loads are growing at the appropriate times. State loads are aggregated by month and by time of day, and future growth rates are compared with historical growth rates. This allows PacifiCorp to review the nighttime growth rates verses daytime growth rates. Growth in the winter months may differ from the growth in the spring and fall. All of this is re- viewed and trends are incorporated to reflect the historical patterns observed. Hourly loads are then totaled across the months of the forecast period to develop monthly loads. This process in- corporates expected weather conditions into the appropriate month based on normal weather patterns. System Peak Forecasts The system peaks are the maximum load required on the system in any hourly period. Forecasts of the system peak for each month are prepared based on the load forecast produced using the methodologies described above. From these hourly forecasted values, forecast peaks for the maximum usage on the entire system during each month (the coincidental system peak) and the maximum usage within each state during each month are extracted. Treatment of State Economic Development Policies The load forecast for each state depends to some degree on the state economic forecast provided by Global Insights. The state economic forecast from Global Insights is dependent on a series of econometric equations based on historical values of state and national economic variables. To the extent that a state has had economic development policies in the past, it is reflected to a similar degree in the state economic forecast and, thus, impacts the load forecast. Periodically, Global Insights will include in the state economic forecast newly developed state economic policies judgmentally external to the econometric forecasting equations when it is deemed appropriate to PacifiCorp 2007 IRP Appendix A Base Assumptions include such programs in the forecast. Since it is assumed that the economic forecast includes an existing and relevant new economic development programs, the load forecast includes the im- pacts of these programs. Elasticity Studies Since the 2004 IRP, PacifiCorp has performed three separate studies on the effects of the price of electricity on electricity usage in Utah. Each study evaluates the increasing block rates of the residential customer class. That is, the increasing price of electricity during the summer should cause a decline in the usage of electricity, especially during times of peak demand in Utah. These three studies can be classified as 1) Total residential class analysis through econometric methods 2) Analysis, using econometric methods, of customers who called about their electric bills and 3) Sub-group analysis of the residential class using cluster analysis and econometric analy- SIS Total Class Analysis An econometric equation with usage per customer as the dependent variable and the real price of electricity, real household income, cooling degree days , heating degree days, real natural gas prices, and lagged use per customer as independent variables was developed. The time period of estimation was from 1982 through 2005. The results of this estimation indicate that the short- term price elasticity was -05 and that the long-term price elasticity was -09. Using either measure, it was determined that electricity is price inelastic, i., having an elasticity measure less than 1 in absolute value, or relatively unresponsive to changes in the price of electricity. In particular, the short-term elasticity measure indicates that for a 10 percent increase in price there is a 0.5 percent decline in the usage of electricity one year in the future. The long-term measure indicates that a 10 percent increase in the price of electricity ultimately leads to a 0.9 percent decline in electricity usage. Analysis of Customers Who Called About Their Bills During 2004 PacifiCorp received calls from 77 customers in Utah who indicated that they were calling about price issues. Of these 77 customers 13 had sufficient data to analyze their usage in response to price changes. An econometric equation was specified having the log of average monthly kilowatt-hours (kWh) as the dependent variable and the log of average real price current and lagged one month, the log of average usage per month lagged on month, heating degree days, and cooling degree days as independent variables. The results of this econometric analysis indicated that the price variables were not statistically significant, which implies that the price coefficient and elasticity is statistically equal to zero. This result means that among those who notified PacifiCorp about changes in their price of elec- tricity, there was no measurable change in their usage. 2 All heating and cooling degree day variables in these analyses were based on temperature data from the Salt Lake City Airport. PacifiCorp 2007 IRP Appendix A Base Assumptions Sub-group Analysis The sub-group analysis used cluster analysis to group customer in accordance with their usage patterns over the last six years. To be included in the analysis, a customer had to be receiving service since July 1999 and the minimum amount of monthly usage was restricted to 55 kilowatt- hours. The number of residential customers satisfying both conditions was 136 042. From this group of customers, the customers were clustered in accordance to their usage monthly usage patterns and amounts since July 1999. Using traditional cluster analysis techniques based on changes in monthly usage patterns and amounts, it was found that there were 23 clusters of 500 or more customers, with the final cluster being aU other remaining customers. For these 24 groups of cus- tomers, regression analysis was performed with the dependent variable being the log of average monthly kilowatt-hours for the group and the independent variables being the log of the group average price per kilowatt-hours, the log of the group average price per kilowatt-hours and the log of the lagged average monthly kilowatt-hours, monthly heating degree days and monthly cooling degree days. Of these 24 groups, two groups indicated a change in electricity usage in response to changes in the price of electricity. One group consisted of 1,490 customers with a summer average usage of 096 kilowatt-hours per month. This group had an elasticity measure of -51 which implies that a 10 percent increase in price would lead to a 25.1 percent decline in electricity usage for this group. The second group consisted of 505 customers with a summer average usage of 2 340 kilowatt-hours per month. This group had an elasticity measure of -95 which implies that a 10 percent increase in price would lead to a 9.5 percent decline in electricity usage for this group. These two groups represent roughly 2 percent of the 136 042 original customers.. The remaining groups, which represented 98 percent of the customers, had no usage response to price changes. When weighing the groups according to their percent representation, the analysis implies that the total price elasticity is -036; i., electricity is price inelastic in total, which indicates that for the total residential class a 10 percent increase in price leads to a 0.36 percent decline in total residential usage. COMMODITY, PRICES Market Fundamental Forecasts PacifiCorp has historically relied on PIRA Energy s long range Reference Case forecast ofnatu- ral gas prices as a primary input to its fundamental forward price curve. The PIRA forecast translated to western delivery points, is used both to forecast electricity market prices in its fun- damentals-based price forecasting model, Multi-objective Integrated Decision Analysis (MIDAS), and directly as fundamental forward price curves for natural gas. PIRA Energy, through its Scenario Planning Service, also forecasts low and high scenarios for natural gas prices and estimates probabilities associated with these cases and the reference case. Prior to the August 2006 forward price curve, PacifiCorp did not use the low and high natural gas price scenarios in the development of its fundamental forward price curve, relying exclu- sively on the reference case. PacifiCorp 2007 IRP Appendix A Base Assumptions Since 2003, when PIRA began its scenario planning service, natural gas prices and price fore- casts have increased dramatically. A number of wen documented supply and demand factors have contributed to this shift. In addition to a higher reference case, market changes have also led PIRA to forecast a wider range of low and high scenarios and higher probabilities associated with the high price scenarios. In its August 2006 update to scenario forecasts, PIRA raised the probability associated with the high scenario from 25 to 30 percent and lowered the low scenario probability from 30 to 25 per- cent. PIRA documented these changes and the explanation for their forecast revisions in their quarterly update. The factors contributing to the shift include the fonowing: Increasing probability of global liquefied natural gas (LNG) supply constraints and higher costs arising from slower expansion ofliquefaction, escalation of project costs, ris- ing global demand competition from emerging economies, higher political and supply disruption risks, and state gas companies' extraction of higher economic rents through royalties that have roughly doubled. Increasing risks to the timing and success of arctic frontier pipelines (Mackenzie Delta and Alaska North Slope). Mounting evidence of a more sensitive price elasticity of supply on the part of US pro- ducers who can rapidly step down exploration and production efforts in response to lower prices, especially in light of continuing high crude oil prices. PIRA's ability to ascribe probabilities to their base, high and low cases will allow changes in any of the scenarios or probabilities associated with them to be reflected. PacifiCorp includes this improvement by probability-weighting PIRA's cases using PIRA's quarterly and annual updates to scenario forecasts. This method is an improvement over the company s historic use of the PIRA reference case forecast because it is responsive to increasing uncertainty surrounding fu- ture natural gas prices and also because it better reflects the current view of higher risk of higher natural gas prices in the future. Should the market outlook change and revert to one with more certainty and less high price risk, the probability weighted forecast will also capture that change. PacifiCorp s official electricity price forecasts are a blend of market prices and output results from MIDAS. PacifiCorp 2007 IRP Appendix A Base Assumptions Modeling Resource Additions in MIDAS There are three general categories of resource additions added to the MIDAS price forecasting model: (1) renewable generation additions under renewable portfolio standard requirements or based on published integrated resource plans, (2) specifically identified new resource addi- tions and (3) other capacity needed to meet load growth and planning reserve. Multiple states in the Western Interconnection have adopted renewable portfolio standards. While renewable portfolio standards vary considerably by state, they all require affected enti- ties to hit pre-specified renewable targets measured as a percentage of retail sales. If the mandated RPS targets in each state are to be met, various types of renewable resources must be added to the Western Interconnection resource supply over time. Not all states and provinces within the Western Interconnection are subject to renewable port- folio standards. However, utilities within these regions have been including renewable gen- eration in their integrated resource plans. The recent history of renewable additions confirms the likelihood of additions specified in integrated resource plans coming to fruition. MIDAS modeling includes this IRP-reflected trend of adding renewable resources in areas unaffected by renewable portfolio standard legislation in the Western Interconnection. Total RPS-required and IRP-reflected renewable resource capacity additions added to MIDAS through 2025 is almost 000 GWh, which represents a mix of wind, geothermal, solar, bio- mass, landfill gas and small hydro projects. New resource additions include specifically identified resource additions within the Western Interconnection and are only added to MIDAS after independent sources have verified that the units are under construction, operational or far enough into advanced development such that completion on-line date can be forecasted with confidence. The MIDAS market resource expansion module adds new capacity in response to market prices or to meet load growth and planning reserves through its automated resource addition logic. Resources evaluated by MIDAS include natural gas simple cycle combustion turbines intercooled aeroderivative simple cycles, and combined cycles (with and without duct firing); coal-fired units; and IGCC units. As regions express preferences for, or restrict the usage of certain resource types (such as coal), the mix of resources that can be added by the model to meet load growth or planning reserves will change. As Figure A.l shows, market prices are used exclusively for the first 72 months. The official August 2006 prices reflected market prices on August 31 2006. Market prices are derived from actual market transactions and broker quotes from polling the industry. Months 73-84 are the average of corresponding adjacent market and MIDAS prices (e.g. month 73 = (market month 61 + MIDAS month 85)12). Starting in the 85th month and through 2025 prices from MIDAS are used exclusively. After 2025 prices are escalated using PacifiCorp s June 2006 inflation curve. The plot in Figure A.l illustrates the blending period. PacifiCorp 2007 IRP Appendix A Base Assumptions Figure A.I- Natural Gas and Wholesale Electric Price Curve Components 120 MIDAS 100 Inflation C'V "'- C'V C'V ,..,.. C'V C") ,.. C'V ,.. C'V "'-,..,.. C'V ,.. C'V f:J C'V C'V f:t For Illustration Purposes Only Gas Price Forecasts As described in the Market Fundamental Forecast section, natural gas prices for the first six years are from the market on August 31 , 2006 and for the next year are a blend of market prices and the gas prices used in MIDAS or PIRA. Starting in year seven, PIRA's natural gas price forecast is used exclusively. Natural gas price assumptions in MIDAS are based on PIRA Energy s July 25, 2006 short-term forecast, the August 3 , 2006 probabilistic weighted long-term gas forecast, and the August 22 2006 long-term gas basis differentials. PIRA gas price projections are used in MIDAS through 2020. An prices are adjusted to be consistent with PacifiCorp s official inflation curve issued in June 2006. Gas prices beyond 2020 are escalated using PacifiCorp s inflation curve, which was updated on June 6, 2006. IRP west side natural gas prices are an average of prices at the Sumas, Stanfield and Opal deliv- ery points. Natural gas prices on the east side are based on the Opal delivery point prices. Fig- ure A.2 shows the natural gas price forecasts used in the 2007 IRP. PacifiCorp 2007 IRP Appendix A Base Assumptions Figure A.Natural Gas Price Curve $12. $9. $11. $10. ::I :;; $8. :;;;;;: $7. $5.-+-20061RP West -8-.2006 IRP East $6. $4. ~ & & ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 5 ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ Year Wholesale Electricity Price Forecasts Figure A.3 shows the annual average of heavy load hours (HLH) and light load hours (LLH) for wholesale electricity price forecasts dated August 31 , 2006 that are used in the 2007 IRP. Figure A.3 - Wholesale Electricity Price Forecast - Heavy Load Hours Light Load Hours $120 $100 $80 $60 iii $40 $20 -+- HLH ...... LLH 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017.2018 2019 2020 2021 2022 2023 2024 2025 2026 Year PacifiCorp 2007 IRP Appendix A Base Assumptions Post-2020 real growth rate sensitivity analysis At the May 10, 2005 public meeting, there was discussion about using real escalation for natural gas prices past 2020. PIRA provides natural gas prices through 2020 and PacifiCorp s official natural gas forecast beyond 2020 is escalated using PacifiCorp s inflation curve. Another credible source, EIA Annual Energy Outlook February 2006, assumes gas escalation beyond 2020 to be approximately 1.5 percent in real terms. This level of natural gas real escalation was run through the MIDAS model and market prices increased on average by 1.8 percent for the period 2012 through 2025. This was felt to be such a small impact that it was not required to run these market prices through the CEM and PaR mod- els. Regional transmission project impact analysis For the regional transmission sensitivity, new transmission lines were added to the MIDAS model topology to determine market price sensitivity. A new 1 500 megawatts line was added from Wyoming to SP15 and a new 1 150 megawatts line was added from Utah to NPI5. These lines were sized to be consistent with the size of new coal plants that were added in Wyoming and Utah by the MIDAS automatic resource addition logic. The average market prices for the period 2012 through 2025 decreased on average by approximately -2 percent. Gas generation is on the margin and determines market prices, which are relatively unaffected by increased transmission. Coal Prices Figure A.4 reflects PacifiCorp s estimate of delivered coal costs for its western control area (West), Wyoming and Utah. These costs figures are projections and remain sensitive to changes in overall supply and demand as well as changes in transportation costs. PacifiCorp 2007 IRP Appendix A Base Assumptions Figure A.4 Average Annual Coal Prices for Resource Additions $3. $2. $3. ::I $2. ii5 :;;:;; ... $1. $1. $0. Wyoming ....-.....Utah West ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ Years The current IRP plan only contemplates siting coal fired plants at PacifiCorp sites in the West Wyoming, or Utah. PacifiCorp has not enclosed the costs of its generation fleet. Rather these costs are reflective of PacifiCorp s actual and projected contract costs rather than as a market indicator for future generating potential. Coal Prices - West Side IGCC The estimated delivered price of fuel delivered to west-side IGCC resources is $1.50/MMBtu in calendar-year 2006 dollars. Published values for a 50/50 blend of petroleum coke and Powder River Basin (PRB) coal from a publicly available document on one of the proposed IGCC pro- jects is estimated at $1.35/MMBtu. The $1.50/MMBtu value reflects uncertainty in the eventual delivered fuel cost, and is considered conservative based on discussions with one party currently proposing an IGCC facility. It is expected that west-side IGCC resources will be able to be fueled with a wide range of fuels with the predominant fuel being low-cost petroleum coke or a blend of petroleum coke and low- cost western fuels, such as PRB coal. Recently proposed IGCC projects in the Pacific Northwest (Energy Northwest's Pacific Mountain Energy Center and Summit Power Group s Lower Co- lumbia Clean Energy Center) are located adjacent to deep water ports with rail access allowing for multiple kinds of fuel to be delivered, including petroleum coke, as well as western and inter- national coals. The range of coals that could be used will depend primarily on the design charac- teristics of the gasifier, the fuel processing equipment, and the capabilities of the syn-gas clean up systems. PacifiCorp 2007 IRP Appendix A Base Assumptions EMISSION. COSTS Carbon Dioxide The CO2 adder is based upon the possibility of mandated green house gas reductions across the S. electric generating sector. The CO2 adder reflects the company s estimate of compliance costs set at $8/ton in 2008 dollars adjusted for inflation using PacifiCorp s official June 2006 inflation curve. To account for the uncertainty surrounding when such a cost will be imputed upon generating units, prices in 2010 and 2011 are probability weighted. The probability weight- ing applied to 2010 and 2011 prices are 0.5 and 0.75 respectively. By 2012, it is assumed that the CO2 policy will be fully implemented. CO2 prices are $4.15/ton in 2010, $6.34/ton in 2011 and $8.62/ton in 2012 and escalate at PacifiCorp s June 2006 inflation curve. The portfolio modeling utilized alternative CO2 cost adders for scenario analysis. These alterna- tive cost adders, along with the $8/ton case, are shown in Table A. Table A.9 - CO2 cost adders used for Scenario Analysis CO2 C()stAt:ld~r Levels ($rron,2008Dollars) Year $0.$15 $38 ,"Ii $61 20l0 20l1 6.34 6.34 6.34 20l2 20l3 20l4 11.05 17.24. 20l5.13.35.67.43 20l6 9.26 17.44.70. 2017 9.43 17.44.71.85 20lX 18.29 45.73. 20l9 18.46.74.45 2020 18.47.75. 202l 10.19.48.24 77. 2022 10.32 19.49.78. 2023 10.20.50.80. 2024 10.20.43 51.81.68 2025 10.20.52.83.20 2026 11.13 21.52.84. Sulfur nioxide The short-teml SO2 allowance price forecast reflects PIRA's May 30, 2006 forecast. The SOl price tmjcctory is based upon the May 2006 Emissions Market Intelligence Service report issued by PIRA with the following adjustments. The PIRA price forecast is provided in real dollars and is adjustcd for inflation using PacifiCorp s official inflation forecast issued in June 2006 to pro- duce a nominal spot price forecast. Prices beyond 2020 are grown using the same official infla- tion curvc. New SOl allowance prices were adopted to align with a PIRA update and EPA' PacifiCorp 2007 IRP Appendix A Base Assumptions Clean Air Interstate Rule (CAIR). CAIR requires 2 existing Acid Rain Program allowances for each ton of emissions beginning in 2010 and 2.86:1 in 2015. This surrender ratio applies to East- ern states, but does not apply in the West. Effectively, this lowers al1owance prices by a factor of 2 in 2010 and 2.83 in 2015. Figure A.5 shows the SO2 spot emission costs used in the 2007 IRP. Figure 5 - Sulfur-Dioxide (SOz) Spot Price Forecast 200 800 000 600 II) 400 200 2007 2008 2009 20102011 2012 2013 2014 2015 2016 2017 2018 20192020 2021 2022 2023 2024 2025 2026 Nitro2en Oxides The NOx price forecast reflects PacifiCorp s expectation that by 2012 some form of annual NOx cap-and-trade program will be imposed in the West. Considering the West does not have the same ground-level ozone problems experienced in the East, the forecast assumes that the NOx trading program imposed in 2012 will be less stringent than what is currently targeted under EPA's Clean Air Interstate Rule (CAIR) for Eastern states. As a result, the marginal control technology is assumed to be selective non-catalytic reduction (SNCR) as opposed to selective catalytic reduction (SCR). While it is by no means certain that a market-based allowance trading mechanism will be imposed eventual1y on western states NOx emissions, this assumption serves as a reasonable proxy for additional control costs that are likely to arise from NOx regulations driven by existing regulations. In 2012 NOx al1owance costs are expected to be $1 145/ton and escalate at PacifiCorp s June 2006 inflation curve. Mercurv Mercury (Rg) prices reflect co-benefits from the installation of SO2 and NOx controls with a cap-and-trade program beginning in 2010. The mercury spot price forecast is based upon PIRA' Emissions Market Intelligence Service as of February 23, 2006. PIRA's forecast includes a range (high and low) for 2010 2015 , and 2020. Values between the years reported by PIRA are interpolated. Al1 prices are adjusted to be consistent with PacifiCorp s official inflation curve issued in June 2006. Mercury prices are expected to be $7 197/Lb in 2010. PacifiCorp 2007 IRP Appendix A Base Assumptions RENEWAB LEASSUMPTI ONS Production Tax Credit The production tax credit (PTC) incentive applies to new wind and geothermal plants with the intent of bringing their costs in line with other resource technologies such as resources fueled by coal and natural gas. In the 2007 IRP, the tax credit is incorporated into the wind supply curves. Although the current law applies only to wind projects brought on-line through 2007, the effect on supply curves was extended throughout the study horizon for the purposes of the IRP analy- sis. It is widely expected that the PTC deadline will be extended, and will only end at such a time as the cost of the technology declines to the point where tax credits are no longer needed to keep wind competitive with other resource types. The 2007 IRP does not contain any specific expectation regarding declining wind resource costs due to technology improvements, using the assumption of an extended PTC to cover the combination of PTC and technology improvementeffects. Renewable Ener2Y Credits Renewable energy credits (RECs), also known as green tags, are certificates that represent the reporting rights for a quantity of energy generated from a specific resource. Markets have devel- oped around buying and selling RECs. Consumers desiring to encourage renewable resources may purchase RECs, sometimes matching all or a portion of their electric power usage.Utilities may also purchase RECs to satisfy minimum renewable energy requirements established in some states. Since PacifiCorp s 2003 IRP, a value has been ascribed to the green tags generated by owned renewable energy projects. That value was estimated to be $5 per megawatt-hour of generation for the first five years of production (constant nominal dollars). PacifiCorp called a number green tag suppliers to ascertain whether the market value of RECs had substantially changed from where it has been over the past few years. Despite the expectation that increasing state minimum requirements for renewable generation would push market prices up, there was no clear indication that market prices had gone up. The potential market impacts of state standards was discussed, but the consensus was that the effect on market prices would be highly dependent on the specifics of state requirements, and did not clearly indicate a specific direction for green tag prices. In light of this, PacifiCorp has chosen to retain its REC value assumption of $5 per megawatt-hour for five years in constant nominal dollars. EXlSTINGRESOURCES Hydroelectric Generation Table A.IO provides an operational profile for each of PacifiCorp s hydroelectric generation fa- cilities. The dates listed refer to a calendar year. PacifiCorp 2007 IRP Appendix A Base Assumptions Table A.IO - Hydroelectric Generation Facilities ./ .., i.' . '.'/'' ,.. . ~aCifiC!()rp i' JJicense .iSh.a...~ "'.', ~,' , . Kx.pi,ration Retirement Plant hi",)',Date Date .. ,. ,.. .. .ii . ...... i. ..' West.'c' Big Fork Montana 2001 2051 Clearwater 1 15.Oregon 1997 2040 Clearwater 2 26.Oregon 1997 2040 Copco 1 20.California 2006 2046 Copco 2 27.California 2006 2046 East Side Oregon 2006 2016 Fish Creek 11.00 Oregon 1997 2040 Iron Gate 18.California 2006 2046 IC Boyle 80.Oregon 2006 2046 Lemolo 1 29.Oregon 1997 2040 Lemolo 2 33.Oregon 1997 2040 Merwin 136.Washington 2009 2046 Rogue 46.Oregon Various Various Slide Creek 18.Oregon 1997 2040 Soda Springs 11.00 Oregon 1997 2040 Swift 1 240.Washington 2006 2046 Toketee 42.Oregon 1997 2040 West Side Oregon 2006 2016 Yale 134.Washington 2001 2046 Small West Hydro 21.01 CA/OR/W A Various Various . '' '. '. ,. East .,'. . , , Bear River 114.ID/UT Various Various Small East Hydro 26.ID/UT/WY Various Various Hydroelectric Relicensing Impacts on Generation Table A.ll lists the estimated impacts to average annual hydro generation from FERC license renewals. PacifiCorp assumed that all hydroelectric facilities currently involved in the relicens- ing process will rece~ve new operating licenses, but that additional operating restrictions imposed in new licenses wiH reduce generation available from these facilities. PacifiCorp 2007 IRP Appendix A Base Assumptions . . Year LostGem~ration (MWh) 2009 (158 191) 2010 (158 191) 2011 (158 191) 2012 (168 035) 2013 (196 590) 2014 (196 590) 2015 (196 590) 2016 (212 383) 2017 (212 383) 2018 (212 383) 2019 (212 383) 2020 (212 383) 2021 (212 383) 2022 (212 383) 2023 (212 383) 2024 (212 383) 2025 (212 383) 2026 (212 383) Note: Excludes the decommissioning of Condit, Cove, Powerdale, and American Fork. Generation Resources Table A.12 lists operational profile information for the PacifiCorp generation resources, includ- ing plant type, maximum megawatt capacity, ownership share, location, retirement date, and FERC Form 1 heat rates. Lake Side s heat rate has been approximated based on design expecta- tions. Table A.I2 - Thermal and Renewable Generation Facilities Carbon 1 Utah 100%2020 11,497 Carbon 2 105 Utah 100%2020 11,497 Cholla 4 380 Arizona 100%2025 815 Montana 10%2029 870 Montana 10%2029 870 Colorado 19%2024 208 Colorado 19%2024 208 Dave Johnston 1 106 100%2020 047 Dave Johnston 2 106 100%2020 047 Dave Johnston 3 220 100%2020 047 Dave Johnston 4 330 100%2020 047 Haden1 Colorado 24%2024 571 PacifiCorp 2007 IRP Appendix A Base Assumptions ii ..,.., MaxinmmMW pacifiCorp I . (PacitlCo..p ... P~rcentage I Retirement . H~afRat~i'~lant ' . Share)Stat~ .1.. ... 'ShllreY .1 ... Date!! ' .. . ffitu/kWh Hayden 2 Colorado 13%2024 571 Hunter 1 403 Utah 94%2031 508 Hunter 2 259 Utah 60%2031 508 Hunter 3 460 Utah 100%2031 508 Huntington 1 445 Utah 100%2025 099 Huntington 2 450 Utah 100%2025 099 Jim Bridger 1 353 Wvoming 67%2026 569 Jim Bridger 2 353 Wvoming 67%2026 569 Jim Bridger 3 353 Wvoming 67%2026 569 Jim Bridger 4 353 Wvoming 67%2026 569 Naughton 1 160 Wvoming 100%2022 426 Naughton 2 210 Wvoming 100%2022 10,426 Naughton 3 330 Wvoming 100%2022 10,426 Wyodak 1 280 Wvoming 80%2028 597 Gas':fired ' . iii '../ .'." ..... .. . Currant Creek 541 Utah 100%2040 327 Gadsby 1 Utah 100%2017 590 Gadsby 2 Utah 100%2017 590 Gadsby 3 100 Utah 100%2017 590 Gadsby 4 Utah 100%2027 556 Gadsby 5 Utah 100%2027 556 Gadsby 6 Utah 100%2027 556 Hermiston 1 124 Oregon 50%2031 222 Hermiston 2 2/124 Oregon 50%2031 222 Lake Side 3/544 Utah 100%939 West Valley 1 Utah 100%2008 694 West Valley 2 Utah 100%2008 694 West Valley 3 Utah 100%2008 694 West Valley 4 Utah 100%2008 694 West Valley 5 Utah 100%2008 694 ' '" ...' . -c- . . Renewables and Other Blundell (Geothermal) Utah 100%2033 Foote Creek (Wind)Wvoming 79%2019 Leaning Juniper (Wind)101 Oregon 100%2031 James River (CHP)Washington 100%2016 200 Little Mountain (CHP)Utah 100%2009 980 1/ Plant lives are currently being reviewed for compliance with future environmental regulations. 2/ Remainder of Hermiston plant under purchase contract by the company for a total of248 MW. 3/ Currently under construction; expected June 2007 start date. 4/ Planned Blundell bottoming-cycle upgrade of 11 MW in 2008. PacifiCorp 2007 IRP Appendix A Base Assumptions Demand-Side Mana2ement This section provides tabular statistics for PacifiCorp s Class 1 , 2, 3 and 4 demand-side man- agement programs. For more information on demand-side management programs, see the fol- lowing: Chapter 4 describes each of the demand-side management program classes. Chapter 4 summarizes how each of the Classes of demand-side management resources was incorporated in the portfolio simulation and analysis process. Class I Demand-Side Management Table A.13 details the base case Class 1 demand-side management programs. Peak load reduc- tions for 2007-2016 are shown by program within each state. Table A.13 - Class I Demand-Side Management Programs Irrigation Load Control Incentive program for Idaho irrigation cus- tomers to participate in pumping load control program during the irrigation season. Residential and Small Commercial Air Condi- tioner Load Control Program -Cool Keeper Turn-key load control network financed, built operated and owned by a third party vendor through a pay-for-performance contract. This program may be expanded in size or expanded into other jurisdictions within this planning period. Irrigation Load Control Incentive program for Utah irrigation custom- ers to participate in pumping load control program during the irrigation season 50 megawatts in 2007 continuing for 10 years. 90 megawatts by 2007 contracted for through 2013. 12 megawatts in 2007 continuing for 10 years. Note: The company discontinued Utah's commercial lighting load control program in August of 2006 following the program inability to reach its targeted curtailment milestones. Class 2 Demand-Side Management Since the 2004 IRP, more current Class 2 data has been incorporated into the 2007 IRP Class 2 DSM in the system load forecast. Adjustments, which increased savings, include the proposed implementation of Wyoming programs and the introduction of the Home Energy savers program for residential customers in Idaho, Washington and Utah in 2006 and proposed for California and Wyoming in 2007. The Energy Trust of Oregon has completed another resource assessment which reduces their expected contributions from their programs over the planning period. Chang- ing federal standards have reduced air conditioning savings available from the Utah Cool Cash program as weB as have impacted other program forecasts. The Utah Load Lightener program which was expected to contribute energy efficiency results in addition to load management op- portunities, was removed to reflect cancellation of the program in early 2006. Business customer programs have been adjusted to reflect the decrease in savings associated with short payback work drying up and the increased time to acquire the higher complexity savings. PacifiCorp 2007 IRP Appendix A Base Assumptions Table A.14 defines the Class 2 programs. Table A.15 provides base case Class 2 demand-side management program savings for calendar years 2007-2016. Table A.I4 - Class 2 Demand-Side Management programs Energy FinAnswer (incentive program) Energy FinAnswer (loan program) FinAnswer Express Recommissioning Self-Direction Credit Irrigation Efficiency Efficient Air Conditioning Program - " Cool Cash" Residential New Construction - "Energy Star Homes Appliance Recycling Program Low-Income Weatherization Program Home Energy Savers Program Energy Education Engineering and incentive package for improved energy efficiency in new construc- tion and comprehensive retrofit projects in commercial, industrial and irrigation sec- tors. Incentives are based on $/kilowatt hour and $/kilowatt reductions. Engineering and financing package for improved energy efficiency in new construc- tion and retrofit projects in the commercial, industrial and irrigation sectors. Incentives for single measure new construction and retrofit energy-efficient projects in commercial, industrial and irrigation sectors. Incentives are based on a prescriptive (pre-detennined) amount dependent on measures installed. Building tune-up services designed to provide customers with low to no cost actions they can take to improve the efficiency of their existing equipment or facilities. Provides large business customers the opportunity to receive credits to offset the Cus- tomer Efficiency Services charge for qualified "self-investments" in efficiency and related demand side management projects. Three part program. Nozzle exchange, pump check and water management consulta- tion, and pump testing that includes a system audit function. Depending on the state incentives for system re-design and replacements are offered or the project is referred to the Ener FinAnswer ro ram. Provide customer incentives for improving the efficiency of air conditioning equip- ment and/or maintaining or converting air conditioning equipment to evaporative cooling technologies. Third party delivered program providing incentives for home builders to construct single and multi-family homes that exceed energy code requirements. Homes are required to have more efficient cooling equipment and a mix of improved shell meas- ures (windows and insulation) to be eligible for incentives. Additional incentives will be available for improved lighting and evaporative cooling. An incentive program designed to environmentally and cost-effectively remove ineffi- cient refrigerators and freezers from the market. The company partners with community action agencies to provide no cost residential weatherization services to income qualifying households. Program may incorporate energy education depending on the state. A broad based residential program offering customer incentives for the purchase of energy efficient lighting, equipment, appliances, insulation and energy efficient prac- tices e.g. air conditioner tune-ups or duct sealing. The program measures may vary between states due to measure specific programs available in some states e.g. Utah' air conditionin efficienc ro am , " Cool Cash" Program provides 6th graders with energy efficiency curriculum and home energy audit kits that include instant savings measures i.e. compact florescent lights, shower- heads, temperature check cards, etc. This program is currently only available in Washington. PacifiCorp 2007 IRP Appendix A Base Assumptions Northwest Energy Efficiency Alliance (NEEA) A series of conservation programs sponsored by utilities in the region and delivered through NEEA designed to support market transformation of energy efficient products and services in Oregon, Washington, Idaho and Montana. Programs include manufac- turer rebates on compact fluorescent bulbs to building operator certification courses. Energy Trust of Oregon (ETO) Energy education and conservation measures implemented by the Energy Trust of Oregon with funding ITom the three percent public purpose charge paid by Oregon customers. The non-governmental delivery agent under contract with the Oregon Pub- lic Utility Commission was created in March of 2002 as part of the state s electric indust restructurin Ie islation, Senate Bill 1149. 2007 29.2S6 S17 29.2SS SI7 2008 28.247 197 S7.SOO 399 2009 24.49 214 SS8 80.707 77S 2010 23.207 2S4 97.8S7 169 2011 22.200 416 119.04S 329 2012 22.198 214 140.234 039 2013 22.197 844 163.428 948 2014 21.68 189 932 184.618 83S 201S 21.1S 18S 2S9 20S.804 OSI 2016 20.182 30S 226.986 311 2007 18.164 S37 18.163 S37 2008 19.168 357 37.329 S79 2009 16.147 982 S3.470 379 2010 14.130 166 61.9S 542 68S 2011 14.123 328 74.6S3 7S7 2012 13.119 374 87.763 627 2013 13.114 624 99.87S 316 2014 12.106 712 112.981 983 201S 11.6S 102 039 123.083 979 2016 11.31 08S 13S.183 019 PacifiCorp 2007 IRP Appendix A Base Assumptions .... .'.. Ener2Y J'rusfof Ore20ll'l'otal' .,''," ..'..........~...."..'... ~HrCalendar .MWa 1./ . . 'lvl,'!a : Year . FirsLYear . FirstYear t r 2007 1O.980 1O.980 2008 840 19.170 820 2009 S76 27.237 396 2010 77 ,088 3S.314 484 2011 088 44.391 S72 2012 840 S3.470 412 2013 220 63.20 SS3 632 2014 220 72.636 8S2 2015 220 82.720 072 2016 220 91.803 292 Class 3 Demand-Side Management Tabk A.l6 defines the company s Class 3 programs. Class 3 programs are treated as reliability resources and are not included within the company s base resources. Table : .\. 16 - Class 3 Demand-Side Management Programs Demand-Side Management Class 3 Pro ram Descri . tilJn Web based notification program that allows participating customers to vol- untarily reduce their electric usage in exchange for a payment at times and at prices detennined by the company. The program is available to customers with loads equal to or greater than 1 megawatt as measured anytime within the last 12 months. The company is considering program revisions that among other program design changes may expand the program to customers with loads ofless than 1 me awatt. Senate Bill 1149 portfolio offering for residential plus greater than 30 kilo- watt commercial and irrigation customers. Program enables customers to potentially reduce their energy costs by shifting the bulk of their energy usa e to off- eak eriods ear-round. Still under development as of the writing of this report, the company has agreed to a critical peak pricing pilot in Oregon fashioned after California investor owned utilities state-wide pricing pilot program. The program will likely be offered to residential and small commercial customers and be run for a two year period as the company collects infonnation on the customer acceptance, behavioral perfonnance, and cost-effectiveness of a larger offer- A program available to general service customers (non-residential, non- irrigation, non-street lighting and non-area lighting) with a maximum power requirement of 15 000 kilowatts or less. It encourages off-peak usage thou h tariff ricin. A program available to residential customers (120 or 240 volt service with a single kilowatt hour meter). It encourages off-peak usage though tariffpric- mg. Em'r~' E\change program On"J,ton Timl' of Use program Ore~on Critical Peak Pricing pilot Idaho Timl' of Day program - businl'ss and farm load customers Idaho Timl' of Day program- residential customers PacifiCorp 2007 IRP . Demand,;SideMllnagellient . . ClaSs 3 Pro ram. ' . ... Utah Time of Day program - residential customers Interruptible contracts Appendix A Base Assumptions Descri A pilot program (1,000 customers) available to residential customers (120 or 240 volt service with a single kilowatt hour meter). It encourages off-peak usage though tariff pricing. The company has interruptible service agreements with a few major special contract customers that allow for service interruption during periods of sys- tem resource inadequacies and in some cases during periods of high market rices economic dis atch . Class 4 Demand-Side Management Table A.17 defines the company s Class 4 programs. Class 4 program resources are naturally taken into consideration through the development of the company s integrated resource planning load forecasts. Table A.I7 - Class 4 Demand-Side Management Programs Do the bright thing" energy efficiency awareness and education advertising PowerForward program Residential do-it-yourself audit Oregon residential web audit Wyoming residential and small commercial energy advisor website. Energy Education Descri doli General advertising messages that focus on low to no cost efficiency and load management tips and infonnation encouraging customers to "Do the bright thing . Campaign activity increases during seasonal peak periods utilizing radio newspaper, buses, customer newsletters, and other media channels. The umbrella tag line is utilized by some of our Class 2 program vendors in their advertising efforts and the general advertising often directs customers to available incentive ro rams to assist them in their ener efficient ursuits. A state of Utah program supported by company and other state utilities that is- sues public service announcements in a stop light manner to alert customers of critical peak usage situations and requests customers to curtail non-essential loads durin ellow and red alerts. Web accessible do-it-yourself paper audit designed to assist customers in identi- fying how they use energy today and providing them economically based rec- ommendations on how to improve the energy efficiency of their homes. Custom- ers can fill-out the audit online or mail in a copy of the completed audit. The com an will com lete the audit anal sis and mail customers their results. Web based do-it-yourself audit designed to assist customers in identifying how they use energy today and providing them economically based recommendations on how to improve the energy efficiency of their homes. The program is funded by the Oregon s public purpose fund monies and operated by the Energy Trust of Ore on. A link to the ro ram is found on the Pacific Power website. Web based conservation advisor and energy advisor programs designed to assist customers in identifying how they use energy today and providing them eco- nomically based recommendations on how to improve the energy efficiency of their homes. The program is offered by the Wyoming Energy Conservation Network through a grant that was supported by PacifiCorp. A link to the pro- ram is found on the Roc Mountain Power website. Although this program is classified as a Class 2 resource due to its energy saving kit and associated savings, the program revolves around energy education, which is a Class 4 attribute. The program provides 6th graders with energy efficiency curriculum and home energy audit kits that include instant savings measures i. compact florescent lights, showerheads, temperature check cards, etc. This pro- am is currentI onl available in Washin ton. PacifiCorp 2007 IRP Appendix A Base Assumptions Transmission System Topology PacifiCorp uses a transmission topology consisting of 15 bubbles (geographical areas) in the East and nine bubbles in the West designed to best describe major load and generation centers, re- gional transmission congestion impacts, import/export availability, and external market dynam- ics. Bubbles are linked by firm transmission paths. The transfer capabilities between the bubbles represent PacifiCorp Merchant function s firm rights on the transmission lines. Figure A.6 shows the IRP transmission topology. Losses Transmission losses are netted in the loads as stipulated in FERC form 714 (4.48% real loss rate schedule 9). Congestion Charges Transmission charges associated with a congestion pricing regime are not modeled. A detailed analysis of the impacts of congestion pricing will be undertaken in a future IRP when details concerning such pricing become available. Figure A.6 - IRP Transmission System Topology PacifiCorp 2007 IRP Appendix A Base Assumptions PacifiCorp 2007 IRP Appendix B DSM Proxy Supply Curve Report APPENDIX B - DEMAND SIDE MANAGEMENT PROXY SUPPLY CURVE REPORT This appendix contains the report Demand Side Management Proxy Supply Curve Report re- ceived from Quantec, LLC as requested by PacifiCorp to support demand side management re- source modeling in the 2007 Integrated Resource Plan. Final Report Demand Response Proxy Supply Curves Prepared for: PacifiCorp September 8, 2006 ..... g~a ntes RaisiJzg the bar in t.lnal;itic:$ Quantec Offices 720 SW Washington, Suite 400 Portland. OR 97205 (503) 228-2992. (503) 228-3696 fax www.quantecllc.com tf:i).. """ed ""'CIed paper Principal Investigators: Hossein Haeri Lauren Miller Gage Quantec, LLC K:\2006 Projects\2006-25 (PC) Proxy DR Supply Curves\Report\FinaIReport 082906.doc 1722 14th St., Suite 210 Boulder, CO 80302 (303) 998-0102; (303) 998-1007 fax 3445 Grant St. Eugene, OR 97405 (541) 484-2992; (541) 683-3683 fax 28 E. Main St., Suite A Reedsburg, WI 53959 (608) 524-4844; (608) 524-6361 fax 20022 Cove Circle Huntington Beach, CA 92646 (714) 287-6521 Acknowledgements We would like to thank Pete Warnken, Jeff Bumgarner, and Don Jones of PacifiCorp for their support in this study. They provided invaluable insight and guidance throughout this study, while allowing us to maintain our independent perspective and objectivity. Their comments on the earlier drafts of our report helped to improve the clarity of its content and the quality of the presentation significantly. We are grateful to Dan Swan, Ken Dragoon, Stan Williams, and Bill Marek for helping us compile the necessary information for the research and providing important comments on the first draft of our report. Quantec PacifiCorp Demand Response Proxy Supply Curves Table of Contents II. III. Introduction.......... ...... .......... ..... ...................................................... .... ...... 1 Demand-Response Resources.............................. ............................................... ................. Class I (Firm) DSM Resources ..............".... ......... ..... ......... .................. ......"........ ... Class III (Non-Firm) DSM Resources......... ................... .................. ..........".. ...... ... Program Concepts................................................................................................................ Fully Dispatchable .......... ........... ................. ......... .................. ............... ........... ........ Scheduled Firm. ..... .......... ........... .............................. ............................ ......... .......... Curtailable Rates................................. ........ ..... ..................... ................................... Critical Peak Pricing ....................................................... ........................ ....... ..... ..... Demand Buyback/Demand Bidding ... ....... ............... .................................... ........... Valuation of Demand Response Resources ........................................... 7 Overview.............................................................................................................................. Benefits of Demand Response.. ................................................ ......... ..........".. ........ Resource Valuation Methods........................................ ...................... .............. ....... Valuation of Economic Benefits............. ........ ............... ............ .............. ..... ....... ..... Treatment of DR Options in Integrated Utility Resource Planning....................... 1 I Demand Response Resource Potentials .............................................. 15 Technical Potentia1........ ........ ........ ................................. ......... ........ .................. ....... ......... . Market Potential... ................. ........ ................... ........................ ..... .......................... ........ ... Achievable Potentials.... ..... ........... ................... ........................ .................... ................... ... Prox y Resource Supply Curves ... .......................... .................. .................................".... ... Resource Potential Scenarios................................. ............................................................21 High and Low ........................................................................................................ Treatment of Metering Costs................... ..................... ........... .................. ........ .... IV.Methodology and Data ............................................................................ 25 Data Requirements and Sources ............................................................................ Methodology for Estimating Technical Potential.................................................. Methodology for Estimating Market Potential......................................................31 Development of Cost Estimates.. ................................. ............... ...... ......... ......... .. .32 Resource Interaction Estimates............................. .... ................ ......... ................. .. .35 Detailed Program Assumptions ............................................................. 37 VI.References..... ....... ........... ................................................ ...... .................. 43 Quantec PacifiCorp Demand Response Proxy Supply Curves Quantec - P PacifiCorp Demand Response Proxy Supply Curves Introduction This report summarizes the results of an assessment of technical, market, and achievable potentials for demand response (DR) resources for PacifiCorp s system overa11 and its two control areas: West (California, Oregon, Washington), and East (Idaho, Utah, Wyoming). The results of this assessment form the basis for producing proxy supply curves for Class I and Class III demand-side management (DSM) resources, which will be incorporated into PacifiCorp s 2006 integrated resource plan (IRP). The project's key ol;Jjectives included: meeting PacifiCorp s IRP regulatory requirements; addressing public comments regarding comparable treatment of DR resources, with respect to power production options in PacifiCorp s resource portfolio evaluation; and assisting the company in further refining DR opportunities. Specifica11y, the project is intended to address an Oregon Public Utility Commission (OPUC) 2004 IRP requirement to evaluate Class I and Class III DSM resources, using a supply curve approach for portfolio modeling in PacifiCorp' s 2006 IRP. In 2007, PacifiCorp plans to complete a more detailed assessment of DSM potentials providing state-specific results. Therefore, this project is to be considered preliminary, and to serve as a "proxy" for the DR portion of that study. The resulting supply curves show the price/quantity relationship for various categories of DR strategies and options within Class I and Class III DSM resources, as defined by PacifiCorp. As part of this project, to facilitate the economic screening of alternative DR options, research was also conducted regarding current utility practices in valuation of DR resources, with an emphasis on identifying key value drivers used in this evaluation. This report is organized in five parts. The remainder of this chapter provides a general overview of DR resources, as well as the specific program concepts used in this study. Section II describes the results of research on DR value factors and valuation methods. Section III reports the results of the DR potential assessment. Section IV describes the general approach and methodology for estimating resource potentials. Detailed data and assumptions used to derive resource potentials for each specific DR resource are described in Section V. Demand-Response Resources Demand-response resources are comprised of flexible, price-responsive customer loads that may be curtailed in whole or in part during system peak load periods, when wholesale market prices exceed the utility's marginal power supply cost, or in the event of a system emergency. Acquisition of DR resources may be based on either reliability considerations economic/market objectives. Demand response objectives may be met through a broad range of price-based (e., time-varying rates and curtail able rates) or incentive-based (e., direct load control) strategies. For the purpose of this project, DR is defined based on PacifiCorp characterization in terms of two distinct classes of firm and non-firm resource options: Quantec PacifiCorp Demand Response Proxy Supply Curves Class I (Firm) DSM Resources This class of DR strategies allows either direct or scheduled interruption of electrical equipment and appliances such as water heaters, space heaters, central air-conditioners, commercial energy management systems, and irrigation pumps. Programmatic options in this class of resources fall into the four following categories: Fully dispatchable programs, 10 minute or less response, up to 87 hours annually (e., direct curtailment of residential air conditioning, water heating, space heating) Fully dispatchable programs, over 10 minute response, up to 87 hours annually (e., commercial energy management system coordination) Scheduled firm up to 170 hours annually (e., irrigation load curtailment) Scheduled firm at 360 or more hours annually (e., thermal energy storage) Pre-determined incentive payments are typically the main instrument for compensating participants in this class of programs. Class III (Non-Firm) DSM Resources Demand response resources in this class differ from those in Class I in that their dispatch is outside the utility's control and, therefore, less reliable or "firm." Resources in this class include curtailable rate programs, time-varying prices (time-of use, real-time pricing, critical peak pricing), and demand buyback or demand bidding programs. Incentives are provided to participants either as a special tariff (curtailable rates, time-varying prices) or per-event payments (demand buyback). Although residential seasonal programs such as Customer Energy Challenge are considered Class III resources, they are not included in this analysis. Arguably, such programs serve better as contingency resources during periods when energy prices are projected to be high and expected to stay high for an extended period of time, rather than as capacity relief resources. Program Concepts Before developing resource potential estimates, it is important to consider how each resource is likely to be structured as a demand response product or program. Using the definitions of Class I and Class III resources above, program concepts were developed as a framework for estimating market potential. For the purpose of this assessment, five specific program concepts were formulated, as described below. Fully Dispatchable Often referred to as direct load control (DLC), these fully-dispatchable programs are designed to reduce the demand during peak periods by turning off equipment or limiting the "cycle" time (i., frequency and duration of periods when the equipment is in operation) during system peak. The offerings for the residential sector are seasonally divided, while the potential with large Quantec PacifiCorp Demand Response Proxy Supply Curves commercial and industrial customers typically focus on summer cooling loads only. Three program concepts in this category of resources were included in the analysis: Winter. Direct load control of water and space heating during winter are the program options considered in this class. This program would be dispatched during the morning and evening peak hours. The largest potential for such a program wiH be in the West control area because of the higher saturation of electric space heating. Incentives are generally paid on a monthly basis. Although there are no large scale DLC programs in the Northwest, Portland General Electric (PGE) and Puget Sound Energy (PSE) have both studied implementation through pilot programs. Nationally, there are many utilities with space and/or water heating controls, including Duke Power, Wisconsin Power and Light Great River Energy, and Alliant Energy. Summer. The main DR product in this group is direct load control of air-conditioning units , which are typically dispatched during the hottest summer days, and are common place due to the relatively high summer loads in warm climates. PacifiCorp currently pays monthly incentives to residential and small commercial participants in Utah's Cool Keeper AC Load Control program. There is approximately 130 MW of connected load for this program. Using a 50% cycling dispatch strategy, approximately half can be expected during an event. In addition to those utilities listed above, Nevada Power Florida Power and Light, Alliant Energy, and the major investor-owned-utilities in California run air conditioner direct load control programs (e., Sacramento Municipal Utility District and San Diego Gas and Electric). Large Commercial & Industrial. Direct control of large commercial and industrial (C&I) customers requires coordination with the existing energy management systems (EMS). The focus of this program is adjustment of the heating, ventilation, and air conditioning (HV AC) equipment during the top summer hours. Incentives are generally paid on a per-kW or per-ton (of cooling equipment) basis. Some utilities running comparable programs include Florida Light & Power, Hawaiian Electric, and Southern California Edison. Scheduled Firm Program strategies that provide consistent reductions during pre-specified hours target customers with usage patterns and technology that allow scheduled shifting of consumption from peak to off-peak periods. Irrigation Pumping. Irrigation load control is a candidate for summer DR due to the relatively low load factor (approximately 30%) of pumping equipment and the coincidence of these loads with system summer peak. Through PacifiCorp s irrigation load control program, customers subscribe in advance for specific days and hours when their irrigation systems wiH be turned off. Load curtailment is executed automatically based on a pre-determined schedule through a timer device. Although a total of 100 MW Although it may be possible to add control of electric hot water heating to this summer program, this study does not address this option due to the declining saturations of electric hot water heating and the relatively low peak coincident demand during summer. Quantec PacifiCorp Demand Response Proxy Supply Curves is contracted with this program, only half is available due to the alternating schedules of program participants. In the Northwest, Bonneville Power Administration (BPA) has run a pilot irrigation program (on a dispatch, rather than scheduled, basis) and Idaho Power has a program similar to that of PacifiCorp. Thermal Energy Storage. For sman commercial and industrial customers, it is possible to have thermal energy storage (TES) cooling systems that produce ice during off-peak periods, which is then used during the on-peak period to cool the building. The system is programmed to use ice-cooling during pre-specified times (typically six hours per day, from April to October) and participants are given incentives on a per-kW or per-ton-of- cooling basis. Curtailable Rates Curtailable rate options have been offered by many utilities in the United States for many years. These programs are designed to ease system peak by requiring that customers shed load (in part or whole) by a set amount or to a set level (e., by turning off equipment and/or by on-site generation) when requested by the utility. Participants are either provided with a fixed rate discount or variable incentives, depending on load reduction; penalties are often levied for participants who do not respond to curtailment events. Large commercial and industrial customers are the target market for those programs that address PacifiCorp s summer system peak. Many utilities provide a broad range of program options, including Duke Power, Georgia Power, Dominion Virginia Power, Pacific Gas and Electric, ConEd, Southern California Edison MidAmerican, and Wisconsin Power and Light. Critical Peak Pricing Critical Peak Pricing (CPP) rates only take effect a limited number of times during the year. In times of emergency or high market prices, the utility can invoke a critical peak event, where customers are notified and rates become much higher than normal, encouraging customers to shed or shift load. Typically, the CPP rate is bundled with a time-of-use rate schedule, whereby customers are given a lower off-peak rate as an incentive to participate in the program. Customers in an customer classes (residential, commercial, and industrial) may choose to participate in a CPP program, although there are certain segments in the commercial sector that are less able to react to critical peak pricing signals. Currently, there are no CPP programs being offered by Northwest utilities. Peak pricing is, however, being offered through experimental pilots or full-scale programs by several organizations in the United States, notably Southern Company (Georgia Power), Gulf Power, Niagara Mohawk, California utilities (SCE, PG&E SDG&E), PJM Interconnection, and New York ISO (NYISO). Adoption of CPP has not been as widespread in the Western states as they have in the East. In the Pacific Northwest, this may be partly explained by the generany milder climate and the fact that, due mainly to large hydroelectric resources, energy, rather than capacity, tends to be the constraining factor. Quantec PacifiCorp Demand Response Proxy Supply Curves Demand Buyback/Demand Bidding Demand buyback and/or bidding (DBB) products are designed to encourage customers to curtail loads during system emergencies or high price periods. Unlike curtailment programs, customers have the option to curtail power requirements on an event-by-event basis. Incentives are paid to participants for the energy reduced during each event, based primarily on the difference between market prices and the utility rates. An major investor-owned utilities in the Northwest and Bonneville Power Administration have offered variants of this option, beginning in 2001. PacifiCorp s current program, Energy Exchange, was used extensively during 2001 and resulted in maximum reduction of slightly over 40 MW in that period. Demand reductions from PacifiCorp s current program are approximately 1 MW. Demand buyback products are common in the United States and are being offered by many major utilities. The use of DBB offerings as a means of mitigating price volatility in power markets is especial1y common among independent system operators including CAISO, NYISO, PJM, and ISO-NE. However, DBB options are not currently being exercised regularly due to relatively low power prices. Quantec PacifiCorp Demand Response Proxy Supply Curves II.Valuation of Demand Response Resources Overview In the Northwest and elsewhere in the country, valuation of DR programs has been the subject of much debate among utility industry experts. Although there is broad agreement on the existence and relevance of a wide range of benefits arising from DR, there is little agreement on how and to what extent these benefits can be attributed to specific DR programs and what metrics might be used to quantify them. In response to this, in 2005 the Northwest Power and Conservation Council sponsored a series of workshops to identify and enumerate value attributes of DR resources and to develop a consistent methodology for their valuation. The Demand Response Research Center in California recently commissioned two parallel studies to investigate alternative frameworks for valuation and cost-effectiveness analysis of DR products. As part of this study, we conducted a thorough search of DR literature, evaluation reports, and utility filings, followed by informal interviews with several industry experts to investigate current practices for evaluating DR resources. The results of this analysis are intended to inform PacifiCorp s process for screening DR resource options and how they might be incorporated in its integrated resource plan. We begin this section with a review of potential benefits and value factors ascribed to DR, discuss the current practices and the basis for valuation of these benefits and then consider alternative approaches for incorporating DR options in the integrated resource planning process. Benefits of Demand Response There are many different views on the types and the relative importance of value factors associated with DR. Industry experts agree on at least three general categories of benefits from DR: economic, system reliability, and environmental (Hirst 2001). Economic Benefits. There is a host of economic benefits to the utility, the consumers, and the power system as a whole that are presumed to arise from DR. Some of these benefits are more tangible and more readily quantifiable than others. Cost avoidance and cost reduction are the main economic drivers for DR. Demand response allows utilities to avoid or defer incurring costs for generation, transmission, and distribution, including capacity costs, line losses, and congestion charges. Economic benefits may also accrue directly to participants in the form of incentives, rate discounts, and greater ability to adjust their loads to prices, thereby gaining greater control over their energy use and managing their energy costs (Braithwait, 2003). DR has also been credited with several harder to quantify economic benefits, such as creating a hedge against market exposure (price objectives), helping create a more elastic demand curve by sending appropriate price signals (elasticity objectives), and reducing the overall market price by alleviating pressure on reserves (market efficiency objectives) (Ruff, 2002). System Reliability Benefits. Demand response reliability considerations are those meant to ensure reliability in power supply and delivery during system emergencies by providing the ability to shed load under emergency conditions. Customer demand management can enhance Quantec PacifiCorp Demand Response Proxy Supply Curves reliability of the electric supply and delivery systems by providing the utility with the means to better balance loads with supply during system emergencies and/or high-use periods. In this context, DR can help improve the adequacy and security of the power supply and delivery (T &D) systems by augmenting the utility's ancillary services, such as supplemental reserve (Hirst, 2002). Potential Environmental Benefits. Demand response resources promote the efficient use resources in general. Depending on the generation fuel mix of the sponsoring utility, this can help reduce externalities in power generation and reduce emissions. Increasingly, utilities have begun to consider the potential effects of future carbon taxes in their DR product design. Although this is by no means an exhaustive list of all potential benefits discussed in DR literature, it represents the most common set of benefits recognized by industry experts. Additional benefits such as risk management, market power mitigation, customer service, and third-party benefits (for example to aggregators and service providers) have also been cited as potential benefits of DR. These benefits, however, generally tend to be less pronounced and difficult to quantify (Peak Load Management AHiance, 2002). Approaches and current practices for evaluating DR resources and quantifying each of the above benefit categories are discussed below. Resource Valuation Methods Current practices in valuation of DR resources largely rely on an extension of the "Standard Practice Manual" (SPM) originally developed in California for evaluating energy-efficiency programs (California Public Utilities Commission, 2001). Of the four tests set forth in the latest version of the SPM, published in 2001 , the total resource cost test (TRC), usually accompanied by the participant test, is the most common method used to screen DR resources by utilities (California Public Utilities Commission, 2003),z A clear instance of the application of SPM to the evaluation of DR resources is found in the California Public Utilities Commission s direction that the SPM be used as an option in evaluating DR , " since it allows an assessment of demand reductions from multiple viewpoints: society, customer, utility, and ratepayer. A review of current practices in valuation of DR benefits indicates that not all benefits discussed above are taken into account by utilities or system operators, mainly due to the fact they tend to be hard to quantify. Potential benefits of DR, common basis for their valuation, and the range of suggested values are summarized in Table 1. Current valuation methods and practices are discussed in greater detail below. The other tests are the Ratepayer Impact Measure (RIM) Test, Participant Tests, and the Program Administrator (or Utility) Test. Quantec PacifiCorp Demand Response Proxy Supply Curves Table 1. Potential Benefits of Demand Response Benefit Category Value FactorS Basis forValuation Range of Values Market-wide Overall economic efficiency (better alignment of supply and demand) Reduction in average price of electricity in the spot market Reduced costs of electricity in bilateral Not Quantified Not Applicable transactions Reduced hedging costs, e., reduced cost of financial options Reduced market power Private entity (e.g. aggregator) benefits Utility System Avoided capacity costs (generation)Benchmarking (peaker unit)$50-$85 Avoided energy costs Benchmarking (market prices)Variable Avoided T&D losses Adders 6%-10% Deferred grid system expansion Marginal (local) T&D costs Variable Customer Incentives Value of payment Variable Reduced power bill (participants)Rates, demand charges Variable Greater choice and flexibility Cash-flow, Option model Variable Reliability Increase in overall system reliability Change in LOLP Not Available Benefits Value of insurance against low-Value of un-served energy probability/high-consequence events (customer outage costs)$3-$5 per kWh Option value (added flexibility to address future events)Not Quantified Not Applicable Portfolio benefits (increase in resource diversity)Not Quantified Not Applicable Environmental Avoided emissions Environmental "adder 8%-12% Benefits Avoided future carbon taxes Not Quantified Not Applicable Vul"ulitm of Economic Benefits With the exception of participant tests, the application of the SPM tests rely on the concept of cost avoidance as the key mechanism for taking into account the economic value of DR. The TRC test, which is often used as the primary criterion for screening of DR resources, takes into account a variety of avoided costs associated with generation, transmission, distribution, and line losses. The avoided capacity and, to a lesser extent, energy costs are the principal economic benefits included in the test. Determination of avoided capacity and energy costs are most commonly based on a benchmarking method. In the case of avoided capacity costs, the approach relics on using average per-unit life cycle cost of a peaker resource (usually a combined- or simple-cycle gas turbine) as a benchmark for screening of DR options. Market price curves are the most commonly-used proxy for determination of avoided energy costs. A voided capacity costs tend to vary across utilities and the program to which they are applied. Regardless of how they are calculated, capacity costs used by most utilities surveyed fall in the range of $50 to $85 per kW-year. In a recent ruling, the California Public Utilities Commission Quantec PacifiCorp Demand Response Proxy Supply Curves authorized an avoided cost of $52 per kW as compared to the previously established avoided cost of $85 per kW, based on the average life-cycle cost of a peaker plant method for screening and valuation of DR resources (CPUC, PG&E Application 05-06-028, 2005). A voided energy costs represent additional benefits from DR programs. Since most DR programs lead to a shift (rather than a reduction) in energy use, the energy benefits are typicany measured in terms of on-peak/off-peak price differential. Other DR programs, such as DLC may result in reductions in energy use, since some portion of the foregone energy use may not be offset by additional consumption during the off-peak period. The latter benefits are especially important in evaluating DR programs from the participants ' point of view , since they tend to directly affect bins. Avoided energy costs have been used to measure the benefits in a number of evaluations of DR programs in the Northwest? Avoided energy costs are also the sole basis for determination of payments in demand buyback and demand bidding programs. Indeed, incentives in an demand buyback programs are structured on the basis of market energy prices, rather than avoided capacity costs. Benefits to the grid system generany fan into two categories: 1) avoided line loss; and 2) value of opportunities to defer system expansion. In the Northwest, both PacifiCorp and PGE have explicitly incorporated avoided T &D losses in their past evaluations of time-of-use and direct load control programs, and Bonneville Power Administration has explicitly included deferral of investments transmission system expansion in its system planning and valuation of DR programs. Direct benefits to customers represent additional benefits likely to result from DR. These benefits generally appear in the form of incentive payments from the utility or lower bills resulting from reductions in demand charges, shift of demand to lower-priced, off-peak periods and potential energy savings. As discussed above, in the case' of DR programs involving a shift in consumption, these benefits tend to be small. In many DR programs, such as time-of-use rates and load control/curtailment programs, portions of the foregone energy use during DR events (high rate or curtailment period) may not be compensated by higher use during off-peak period thus resulting in net reductions in the customer s energy consumption. Other potential benefits to customers, such as greater choice and "option value " are generally more difficult to quantify. Attempts at quantification of these benefits generany rely on either a discounted cash-flow analysis or an "option model" (see Sezgen 2005). Valuation of System Reliability Benefits The planning and screening of utility-sponsored DR programs typically have not included reliability benefits. But reliability has been the primary metric for valuation of DR programs offered by independent system operators (ISOs). Most of the seven established ISOs have been actively engaged in offering DR options. Since the primary goal of an ISO is to maintain system reliability, it stands to reason that valuation of their programs would be based on reliability These include evaluations of irrigation load curtailment and pilot time-of-use programs offered by PacifiCorp, evaluations of residential time-of-use and direct load control programs by PGE, and Bonneville Power Administration s evaluation of remote irrigation load control. Quantec PacifiCorp Demand Response Proxy Supply Curves benefits rather than avoided generation capacity. Indeed, evaluations ofISO-sponsored programs completed to date have focused almost exclusively on reliability benefits based on avoided congestion, valued in terms of the location-specific marginal transmission costs (LMC). The general approach used in valuation of ISO-sponsored DR is based on two factors: 1) the difference between market power price and the DR program costs; and 2) the expected marginal value of increased reliability realized through assumed reductions in loss-of-Ioad probability (LOLP) and its impact on the expected value of un-served energy (EVUE) as a function of the value oflost load (VOLL), that is: EVUE Value of Lost Load (VOLL) L1 LOLP Load at Risk The underlying concept in the evaluation approach is that the value of curtailable load (therefore the value of the DR programs that generate it) is a function of the "expectation" of future loss of load. This suggests that the actual value of DR programs stems primarily from their societal value as a hedge against low-probability, high-cost events and the associated outage costs to customers. The NYISO and ISO-NE have both used this approach in evaluation of their DR products (RLW Analytics, 2005). Calculation of changes in LOLP and the value at risk are generany established on an event-by-event basis and tend to be highly variable. In its evaluations, the NYISO, for example, typically has assumed a VaLL of $S.OO/kWh (NYISO, 2004); and the PlM Interconnection recently proposed a VOLL of $20/kWh. However, as data on several real-time pricing programs suggest, the VOLL tends to fan in the range between $3/kWh and $5/kWh (Barbose 2004, Violette 2006). Available estimates ofVOLL are calculated from the customer or societal perspectives and are generany expressed in terms of energy, rather than capacity. Presumably, given the actual, program-specific hours of curtailment, it may be possible to convert these estimates to an equivalent capacity value. Valuation of Environmental Benefits Demand response has the potential to produce tangible environmental benefits by avoiding emissions from the operation of peak units as wen as potential conservation effects (load shed versus load shift) during peak periods. Such environmental impacts, however, depend entirely on the emissions profile of the utility's generation resource mix. It is also possible that reduced emissions during peak periods might be offset by increased emissions during off-peak periods, as wen as from additional emissions from on-site, back-up generation at commercial and industrial facilities. Due partly to these complexities, potential environmental benefits are not currently being considered in valuation of utility-sponsored DR programs. Treatment of DR Options in Integrated Utility Resource Planning Classification of DR Options Values arising from DR options, and the manner in which they are incorporated in the integrated planning process may vary by the type of DR product and the entity that sponsors them. There have been several attempts at classification of DR programs. The most common approach to Quantec PacifiCorp Demand Response Proxy Supply Curves classification of DR involves characterizing them according to the degree of the utility's dispatch control. From this perspective, DR resources are generally categorized according to a "firm versus "non-firm" dichotomy. Another approach, adopted in the recent report by the US. Department of Energy, classifies DR programs in terms of the basis on which participants are compensated and proposes two categories: tariff-based and incentive-based (DOE, 2006). A third approach, suggested in a recent study sponsored by the Rocky Mountain Institute (Rocky Mountain Institute, 2006), classifies DR resources along two dimensions: 1) the criteria that trigger a curtailment request by the utility (economic versus reliability); and 2) the method by which utilities motivate customers to participate in DR (load response versus price response). These approaches, however, generally do not provide guidance as to how DR benefits and costs might be allocated or how various resources might be modeled in an integrated resource plan. Arguably, from a utility's perspective, the most important benefits of DR are economic (reducing the overall supply cost) and reliability (offering an optional resource in case of system emergencies). An alternative, and perhaps more appropriate, classification of DR would be in terms of the degree of variability in curtailment period and prices paid by the sponsoring utility.4 Under this scheme, DR resources are classified in terms of two dimensions: curtailment period and incentive payment. As shown in Figure 1 , both period of curtailment and the level of incentives paid by the utility to motivate curtailment may be either fixed or variable. (See Neenan, 2006. Figure 1. Classification of Demand Response Programs Incentive Payment Fixed Variable .... . ro .!! t: i :::J .- () ;::. 'tJ "0 ii: ;:: c.. Time-of-use rates and critical peak pricing are examples of programs where both pricing period and price levels are fixed. Demand buy-back and demand bidding demand response strategies are examples of programs where both price periods and levels of payment are variable. Quantec PacifiCorp Demand Response Proxy Supply Curves Time-of use, load control, scheduled curtailment, and curtailment contracts are examples of resources where both incentive payments and curtailment periods are fixed in advance. Although this group of programs offers more predictable prices and, to a lesser extent, amounts of reduction, they also pose a degree of price risk in that program prices are set in advance through the use of price forecasts rather than based on actual prices at the time of load reduction. Demand buyback and demand bidding, on the other hand, are resources where both curtailment period and incentive payments are variable. Incorporating DR into the IRP Process Much the same as energy efficiency resources, DR products may be incorporated into the IRP in two ways. The first approach, often referred to as "decrementing," begins with pre-screening of DR resources for general cost-effectiveness based on an external benchmark (generally avoided capacity costs), decrementing the load forecast by the amount of DR resources that pass the screening, and solving for the true avoided cost as derived from the value of decremented load to the resource portfolio. The second approach entails simultaneous modeling of generation and DR resources in the context of an optimization or system expansion planning model and selecting the optimal, least cost, mix of resources. In our view, the latter approach is preferred in that it treats DR resources on a level playing field with supply options and forces the model to select from the most attractive, least-cost mix of resources regardl~ss of their classification as supply or demand- side. The main shortcoming of these approaches to valuation and integration of DR resources is that they generally focus on economic (cost-reduction) benefits of DR and ignore the reliability benefits. Moreover, the economic benefits of DR often are measured in terms of energy, rather than capacity, values. For most DR resources, the benefits ought to be evaluated primarily in terms of an alternative , " optional" capacity resource and secondary energy benefits (in terms both reduced consumption and/or peak-off-peak energy costs differential). Regardless of the method used, it is important that the fun range of economic values (including avoided capacity, energy, and T &D benefits, as wen as reliability benefits) be fully considered in the screening and planning processes. Although the greatest value of DR options is likely to be on the generation side, additional benefits such as avoided T &D losses and reliability benefits may be incorporated in the valuation as utility-specific "adders. An additional shortcoming of these approaches is that they ignore the role of risk and uncertainty associated with various resource options. Clearly, there are technical (e.g. equipment failure) and market (e.g. program and event participation rates) uncertainties inherent in any demand- response option. These risks need to be explicitly taken into account in screening of DR resources. It is equany important in the context of IRP that the treatment of DR risks be symmetrical; that is, the screening process ought to also take into account upside risks of DR. Since DR resources are valued on the basis of expected future loads and power prices, future fluctuations in loads and avoided costs are likely to have a direct effect on the value of DR options. 5 Portfolio management principles and techniques are being used in a limited way by some utilities to analyze uncertainties in the IRP process. This is particularly the case in designing standard renewable portfolios in several Quantec PacifiCorp Demand Response Proxy Supply Curves In the context of IRP, joint consideration of economic (capacity and energy) and reliability benefits does, however, pose additional complexity. Since integrated resource planning processes are general1y based on long-run resource needs, the value of DR hinges on its ability to displace some portion of the utility's peak demand. As pointed out in the Department of Energy s recent report, once DR resources are included in the utility's capacity resource mix, they become part of the planned capacity and are no longer available for dispatch during system emergencies (DOE 2006). It is important, therefore, to distinguish between DR resources that serve the economic objectives and might be incorporated in the resource plan and those that are more appropriately set aside for reliability purposes. Certain DR resources, such as demand bidding or demand buyback, may be set aside as reliability options to be called upon during system emergencies. Potential adverse customer impacts are additional considerations in DR planning. Clearly, once DR resources are incorporated in the planned capacity, the utility can maximize the value of DR resources by exercising these options to the maximum extent possible. However, the more frequently these options are exercised, the higher the likelihood of more severe disruptive impacts of the customers ' operations. This will affect the customers ' decision to participate in the DR program and thus reduce the market potential for DR. jurisdictions. For a discussion of uncertainty in IRP and the portfolio management approach see Awerbuch (1993 and 2005). Also see Bolinger (2005) for a survey of current utility practices in portfolio design. Quantec PacifiCorp Demand Response Proxy Supply Curves III.Demand Response Resource Potentials The approach to estimation of resource potentials in this study distinguishes between three definitions of demand-response potential that are widely used in utility resource planning: technical, market, and achievable potentials. Technical potential assumes that an demand- response resource opportunities may be captured regardless of their costs or market barriers notwithstanding obvious exceptions such as load control in mission-sensitive operations. Market potential, on the other hand, represents that portion of technical potential that is likely to be available over the planning horizon, given resource constraints and prevailing market barriers. Finany, achievable potential recognizes that not all of the market potential can be implemented due to the overlap (or interaction) among DR options targeted for the same sectors and/or end uses. To the extent possible, we have sought in this study to obtain the most recent and reliable data on market prospects for various DR options, relying upon available resources from other utilities offering similar products. However, information and assumptions. based on current demand response experiences and costs, no matter how accurate, are subject to future uncertainty. Therefore, the results of this study are to be viewed as preliminary and indicative rather than conclusive. The general methodology and analytic techniques used in this study conform to standard practices and methods used in the utility industry. Given the scope and timeframe of this study, it was necessary to utilize a consistent and relatively simple methodology to effectively address PacifiCorp s immediate IRP needs. The methodology and inputs assumptions are funy described in Sections IV and V of this report. Technical Potential In the context of demand response, technical potential assumes that all applicable end-use loads in an customer sectors, are at least partially available for curtailment, except those customer segments (e., hospitals) and end uses (e., restaurant cooking loads) that do not lend themselves to curtailment 6 and for those programs (e., direct load control) that utilize cycling strategies. Table 2 provides for each customer class (industrial, commercial, irrigation and residential) the technical potential in MW at the system level. (Separate results for the East and West control areas are provided in Appendices 1 and 2.) From a strictly technical perspective, critical peak pricing is expected to have the largest potential due to its broad-based eligibility, fonowed by curtailable rates and demand buyback. In the absence of market constraints, these figures should Although hospitals generally rely on some on-site generation capability, which may be called upon by the utility as a dispatchable resource, such resources are not being considered in this study. Arguably these units are likely to be needed by the host facility during the same period as the utility and are therefore unlikely to be made available for dispatch. Quantec PacifiCorp Demand Response Proxy Supply Curves be viewed largely as estimates of "technical feasibility" only and a measure of the total load that is technically available for demand response. Table 2. Technical Potential (MW), System Fully Dispatchable Scheduled Thermal Critical Sector Large Firm-Energy Curtailable Peak Demand Winter Summer Rates Buyback . . C&I Irrigation Storage Pricing Industrial - - -- - - 194 - - -- - - 510 531 500 Commercial - - - 133 232 130 Irrigation - - -- - - 381 - - -- - -- - -- - - Residential 374 351 - - -- - -- - - 618 - - - Total 374 406 244 381 642 380 630 % of System 16% Peak To provide an illustration of the methods used to estimate technical potentials, the fully dispatchable winter program will be used. First, eligibility for this program is limited to residential customers due to low saturation of electric space and water heating in other customer classes. Next, PacifiCorp energy sales and system and end-use load shapes indicate that the total residential space and water heating loads during the top 87 hours of the winter average approximately 580 MW and 250 MW, respectively. Although DLC programs can fully interrupt this load when installed, it is assumed that a 50% cycling strategy is used, and only 90% of this is technically available to account for the fact that not all systems can be retrofitted with DLC equipment. Therefore, the system-level technical potential, as shown in Table 3 , is 374 MW. Market Potential Market potential is the subset of technical potential that may reasonably be accessible by program strategies, accounting for market barriers and customers ' ability and willingness to participate in demand response programs. For the majority of demand response options, market potentials are estimated by adjusting technical potential by two factors: expected rates of program" and "event" participation. For all programs options, estimates for both program and event participation are derived based on the experiences of PacifiCorp and other utilities offering similar programs. In the case of curtailable rates and demand buyback, market potentials are estimated based on observed price elasticity of load response. See Figure 2 for a comparison of technical and market potentials for various program options. As shown in Table 3, curtailable rates have the highest market potential (144 MW), followed by summer DLC and irrigation. Quantec PacifiCorp Demand Response Proxy Supply Curves Figure 2: Technical and Market Potential (MW), System :!: 600 1,400 200 000 800 600 400 200 l1li Technical Potential II Market Potential !::!::!::!:: :;:... CJ)a.. CJ) ...J :;:... "'0 !:: Q) a.. u:: !:: 1:: "'0 "'0 CJ) Table 3. Market Potential (MW), System . Fully Dispatchable Scheduled Thermal Curtailable Critical . . DemandSectorWinterSummerLargeFinn-Energy Rates Peak Buyback C&I Irrigation .Storage Pricing Industrial - - -- - -- - -- - - 115 Commercial - - -- - - Irrigation - - -- - -- - -- - -- - -- - -- - - Residential 118 - - -- - -- - -- - -- - - Total 120 144 % of System Peak 1.4%0.4% For a ful1y dispatchable winter program, an expected load participation rate of 20% (based on experience of similar programs) and event participation rate of 100% are assumed. This assumption is based on the fact that, absent customers' ability to override curtailment and no equipment failure, load interruption would occur once the load is dispatched by the utility. Reliability of direct load control systems is primarily a function of the type of equipment and communication systems used to affect control such as radio frequency, telephone networks, wide-area networks, or power line caITier systems. Historical experience with systems has shown that the assumption of a zero failure rate may be unjustified. Quantec PacifiCorp Demand Response Proxy Supply Curves Based on these assumptions, this program could reasonably be expected to provide approximately 75 MW ofload reduction for the PacifiCorp system. Using price elasticity of load participation and a measure of commercial and industrial customers' willingness to participate in demand buyback , market potential for this option is estimated at 28 MW. As discussed in Section IV of this report, the elasticity estimates were calculated based on data available on 2000-01 demand buyback program experience of Northwest utilities. Data available on PacifiCorp s 2000-01 Energy Exchange program indicate approximately 40 MW of reduction at an average cost of approximately $100 per MWh. The estimated 28 MW of future market potential may prove overly optimistic due to the dramatically different market conditions prevailing today. Reductions similar to those achieved in 2000- could be difficult or impossible to repeat if electricity prices and customer concerns over energy market conditions continue to be low. Indeed, based on PacifiCorp s program records, operation of the Energy Exchange program during the past three years has resulted in a maximum reduction of no more than 1 MW. Achievable Potentials In analyzing levels of achievable potential it is important to take into account two factors: resource interactions and load reduction being achieved given existing programs. Achievable potentials, therefore, represent unique impacts of various DR program options net of the impacts of existing programs. Estimates of market potentials presented above provide "stand alone estimates of potential. In calculating achievable potential, it is also important to take into account the interaction among DR programs that target the same customer sector and/or end uses within the same sector. Generally, interaction may be accounted for by first ranking competing programs by levelized cost and then allocating the market potentials based on an "availability" factor For the purpose of this study, we have assumed that DBB and scheduled firm irrigation are fully available; therefore they have been assigned an availability factor of 100%. Since curtailable rates and dispatchable large C&I compete for the same target market as DBB, only a portion of their market potential will be available. In the residential and small commercial sector, the summer DLC program is fully available; however, thermal energy storage would only be partially available as it competes with the commercial sector DLC program option. As shown in Table 4, the DR options considered in this analysis may be expected to provide 373 MW of capacity for the PacifiCorp system. In 2005 , the PacifiCorp system peaked 940 MW with 570 MW and 1 540 MW of load occurring during the top one percent and ten percent of the load duration curve. The estimated achievable potentials for DR provide the opportunity to offset 66% of the top one percent and 25% of the top ten percent of the system peak load. 8 Technically, this is the percentage of the market potential that remains after accounting for resource interactions. For example, a 25% availability factor would be multiplied by the market potential to arrive at the achievable potential on a program-by-program basis. Quantec PacifiCorp Demand Response Proxy Supply Curves Summer DLC (120 MW), irrigation (95 MW), and curtailable rate (72 MW) are expected to provide the highest levels of achievable potential. Yet, approximately 114 MW of the identified potential is already under contract through PacifiCorp s Cool Keeper (65 MW), irrigation load curtailment (48 MW), and Energy Exchange (1 MW), resulting in a remaining achievable potential of 259 MW. Therefore, in addition to achievable potential, Table 4 also provides potential net of current programs. Table 4. Achievable Potential (MW) - System . Fully Dispatchable Thermal Critical . . Large Irrigation Energy Curtailable Peak.Demand TotalWinterSummerRatesBuyback C&I Storage Pricing Achievable 120 373 Potential Current Program - - -- - -- - -- - -- - - 114 Potential Net of 259 Current Programs Proxy Resource Supply Curves Supply curves are constructed to show the relationship between the cumulative quantities of DR resources and their costs. Development of supply curves first requires the estimation of per-unit costs. Demand response strategies vary significantly with respect to both type and cost levels. Applicable resource acquisition costs for DR generany fan into two categories: 1) fixed direct expenses such as infrastructure, administration, maintenance and data acquisition; and 2) variable costs. In the category of fixed cost, this study distinguishes between initial development and on-going program administration and operation costs. Variable costs also fall into two categories: costs that vary by the number of participants (e., hardware costs) and those that vary by k W reduction (primarily incentives). Although a large number of national programs were researched for this project, the reporting of costs. particularly development and ongoing administrative costs, were found to be either unavailable or difficult to measure. For the purposes of this study, to the extent possible, we have relied primarily on administrative costs associated with PacifiCorp s other, similar programs, or have adopted rough estimates available from other utilities. See Section IV for specific cost assumptions for various DR options. In developing proxy supply curves, an program costs were first anocated annuany over the expected program life cycle (10 to 15 years) discounted by PacifiCorp s real cost of capital at l (~o to estimate the per-kW levelized9 costs for each resource. Resources were then ranked based on their levelized costs along the supply curve. Figure 3 displays per-unit costs for the various DR options. Lc\'cli/.cd costs represent the annual contract cost , per kW/year, for each DR option. This approach provides mcans for treating all DR on a consistent basis with supply alternatives in the IRP framework. Quantec PacifiCorp Demand Response Proxy Supply Curves $140 $120 $100 ... C'CI $80 ;:.. $60 $40 $20 Figure 3: Levelized Resource Costs ($/kW /year) $118 ffi IJ) it ..cc::: ;:., III ;:., ...J OJ .!!1 1;;ffi l!i 11..c: ro .c:co .c:IJ) IJ)ffi.c:IJ).c:I-- u. .2:- Figure 3 indicates that, with the exception of the irrigation program, per-unit costs tend to increase with the level of firmness of the load: the more reliable the load reduction, the more costly the program. Demand buyback, at $14/kW/year, is expected to be the least expensive option. This program, although relatively inexpensive, provides possibly the least reliable load reduction among the eight program options. Firm irrigation is the next lowest-cost resource at $28/kW/year. Because reductions by this program are pre-determined and scheduled, it is an effective program for achieving firm seasonal load reductions. However, its value as a reliability option is limited because 100% capacity reductions are already incorporated into the utility's planned resource capacity, and hence cannot be "called" to provide load relief during system emergencies. Critical peak pricing ($49/kW/year) provides the ability to notify customers of curtailment events; national experience indicates the potential for reductions can be significant, but customer acceptance and response have generaHy been lower than expected. Curtailable rate programs ($50/kW/year) may provide additional dependability due to contract requirements on customers and may serve as an effective option for reliability purposes. Owing mainly to hardware costs and incentives required of fuHy dispatchable resources, per-unit costs for the three direct load control programs exceed $59/kW/year. Finally, thermal energy storage is expected to be the most costly option with a per- unit cost of$118/kW/year. The proxy supply curve for the eight resource options investigated in this study was constructed based on estimated achievable resource potential net of current programs and per-unit cost of each resource option. Figure 4 displays graphical presentation of the supply curve, which Quantec PacifiCorp Demand Response Proxy Supply Curves represents the quantity of resources (cumulative MW) that can be achieved at or below the cost at any point. Cumulative MW is created by summing the achievable potential net of current programs along the horizontal axis sequentially, in the order of their levelized costs. For example, the irrigation program has 47 MW available, and its cost is second lowest. Therefore its quantity is added to the 27 MW of DBB , showing that in total, 74 MW of resources are available at prices equal to or less than $28/kW. Figure 4. Cumulative Supply Curve, System $125 Therma Storag $100 $75f/) Q) $50 ...J $25 . OLC C&I OLC Win! r . OLe Summer . CriticalPeak.Curtailable Irrigation . OBB It) ...... It) ...... It) ('t') Cumulative MW Resource Potential Scenarios High and Low For the purpose of IRP modeling, achievable potentials were estimated under three scenarios: base case, high, and low, corresponding with PacifiCorp s projected on-peak market prices of $40/MWh (low), $60 (base) and $100 (high). To account for the relationship between market prices (and incentives) and program potential, high scenarios generally assume aggressive marketing efforts and higher incentive levels and, therefore, higher program participation. The low scenario reflects a less aggressive marketing effort and relatively weak program participation. (See Sections IV and V for assumptions underlying the two scenarios. The high and low scenarios for the DBB and curtailment contract options were constructed based on load response elasticity estimates. As reported in the 2006 Department of Energy s Report to Congress, commercial and industrial customers have typically exhibited an inelastic response Quantec PacifiCorp Demand Response Proxy Supply Curves prices (elasticity = 0.1) in load curtailment. This figure was used as a basis for the high and low program participation scenarios for the fully dispatchable large commercial and industrial and curtailable rates options. For the DBB program, a price elasticity of 1.45, estimated based on the 2000-2001 regional data on demand buyback programs, was used to develop the high and low scenarios. (See Section IV for a discussion of methodology and data. The results for the three scenarios are shown in Table 5. Generally, as the potential increases, so does the per-unit costs, due to higher incentives and marketing costs. Yet, in a few cases, such as critical peak pricing and fully-dispatchable commercial and industrial programs, per-unit costs are expected to fall from the low to the base case due to economies of scale; lower marginal per- unit costs result from the fact that fixed program costs are spread over a larger number of units. Table 5. High, Base, and Low Costs and Quantities System Fully Dispatchable Scheduled Thermal CriticalCurtailable Demand Winter Summer Large Firm-Energy Rates Peak Buyback C&I Irrigation Storage Pricing Low Achievable Potential MW Resource Costs ($/kW/yr)$58 $53 $167 $29 $115 $39 $91 $13 Base Achievable Potential MW 120 Resource Costs ($/kW/yr)$76 $59 $84 $28 $118 $50 $49 $14 High Achievable Potential MW 141 114 Resource Costs ($/kW/yr)$84 $72 $102 $37 $119 $86 $45 $18 Treatment of Metering Costs The DR scenarios presented above include metering costs, where applicable (please see Section V for detailed assumptions). In the future, these costs may not be necessary if advanced metering technology is implemented in PacifiCorp s territory. Therefore, this additional scenario excludes metering costs from the base estimates of per unit cost. Figure 5 below displays the new figures and Table 6 provides a comparison of the base (with metering) scenario and the alternative (without metering). The exclusion of meter costs makes little difference (Jess than $1/kW/year) in all programs, except critical peak pricing where the reduction equals $7 IkW/year. Quantec PacifiCorp Demand Response Proxy Supply Curves Figure 5. Per Unit Resource Costs - Excluding Metering Costs $140 $120 $100 ... 1'0 $80 $60 $40 $20 $118 ffi :s: ffi ::J(J) c;a tJ) ffi...J If)tJ)tJ) ... it tJ)a:::::0- (J)::J ::0-tJ) .!!! ffi c.. ffi.r:.r:I-- (J) .r: c..If) .r: c..If) .r: c..If) Table 6. Comparison of Costs with and without Metering Costs Fully Dispatchable Scheduled Thermal CriticalCurtailable Demand Winter Summer Large Firm-Energy Rates Peak Buyback C&I Irrigation Storage Pricing With Meter Costs $76 $59 $84 $28 $118 $50 $49 $14($/kW/year) Without Meter Costs $75 $58 $84 $27 $118 $50 $42 $14($/kW/year) Quantec PacifiCorp Demand Response Proxy Supply Curves IV.Methodology and Data The development of proxy supply curves requires both reasonable approximations of available quantities and reliable estimates of procurement costs for each DR resource. With respect to quantities, the overall approach in this project (see Figure 6) distinguishes between three definitions of DR resource potential that are widely used in utility resource planning: technical, market and achievable. Load shapes for the PacifiCorp system, East/West regions, customer segments, and end use load shapes combine with sales data to produce hourly load profiles. For each DR strategy, technical potential is estimated by applying end use and sector applicability, while market potential additionally incorporates program and event participation. Achievable potential estimates also consider interactions among programs and current DR offerings at PacifiCorp. Finally, proxy supply curves show the relationship between achievable potential and the expected per-unit cost of each strategy. Figure 6. Schematic Overview of Methodology System Load Sector/Segment Load Shapes Sector/Segment Loads Demand Response Strategy End-Use Load Shapes End-Use Loads Class & End-Use Applicability Technical P Current Utility Practices otential Program ParticipationEvent (Load) Participation Market Potential Program Interaction Current DR Programs Achievable Potential Resource Costs Proxy Supply Curves Quantec PacifiCorp Demand Response Proxy Supply Curves Data Requirements and Sources Development of DR supply curves requires the compilation of a large and complex database on load data, end-use and appliance saturations, demand response impacts, and costs, gathered from multiple sources. To the greatest extent possible, this study relies on data available from PacifiCorp on loads, sales, end-use load profiles, and estimates of administrative costs. Secondary data sources were utilized for estimates of DR program impacts. Specific data elements and their respective sources are listed in Table 7. Table 7. Data Elements and Sources Data Element Source -' Various Years Total Sales by Customer Class PacifiCorp, 2005, Table A Commercial Segmentation PacifiCorp, 2005, Commercial Survey (by participants) Hourly System and Regional Load Profiles PacifiCorp, 2005 EIA, Commercial Buildings Energy Consumption Survey (CBECS) EIA, Residential Energy Consumption Survey (RECS) End-Use Shares and Load Shapes Northwest Power Planning Council PacifiCorp PGE Quantec Load Shape Library Existing PacifiCorp Demand Response PacifiCorp studies, various yearsPrograms PacifiCorp, California Energy Commission, Peak Load Management Demand Response Impact Estimates Alliance (PLMA), Edison Electric Institute (EEl), Lawrence Berkeley National Laboratories (LBNL), Various RTO and Utility Reports Department of Energy Demand Response Program Costs PacifiCorp, Other Utilities, Regional Transmission Organizations Methodology for Estimating Technical Potential Within the context of demand response, technical potential assumes that all applicable end-use loads, in all customer sectors, are at least partia11y available for curtailment, excepting those customer segments (e., hospitals) and end-uses (e., restaurant cooking loads) that clearly do not lend themselves to curtailment. Demand response options are not equa11y applicable to or effective in all segments of the electricity consumer market, and their impacts tend to be end-use specific. In recognition of this fact, this methodology employs a "bottom-up" approach, which involves first breaking down system loads for each of PacifiCorp s two control areas into sectors, market segments within each sector, and applicable end uses within each market segment. Demand response potentials are estimated at the end-use level and then aggregated to sector and system levels. This approach is implemented in four steps as fo11ows. I. Define customer sectors, market segments, and applicable end-uses. The first step in the process involves defining appropriate sectors and market segments within each sector. Given the available data, this study includes four customer classes (residential commercial, industrial, and irrigation), the eleven commercial segments defined in Quantec PacifiCorp Demand Response Proxy Supply Curves Commercial Building Energy Consumption Survey (Education, Food Stores, Hospitals Hotels/Motels, Other Health, Offices, Public Assembly, Restaurants, Retail, Warehouses and Miscel1aneous), and total industrial loads. 2. Create sector and segment load profiles. Using available local hourly load profiles service area sales are used to generate sector- and segment-specific load shapes. Figure 7 displays the load duration curves for East, West and System overall, and Figure 8 shows the typical daily system load profiles. Figure 9 exhibits sector load shapes; the "System shown is the actual load and "Total Sector" is the sum of load by sector. The difference between these lines are due to loads that are not amenable to demand response, such as traffic and street lighting, and loads not directly attributable to end use load profiles. Figure 7: PacifiCorp Load Duration Curve, 2005 10,000 000 000 -Total-East -West 000 000 ~ 5,000 000 000 000 000 - ~ ~ a M m N W W - ~ ~ 0 M m N W W ~ ~ ~ 0 M m N W W - ~ ~ 0 Mwow ~ ~ N ~ M M m ~ m ~ 0 wow N ~ N ~ M M m ~ m ~ a N ~ a N ~ 0 N ~ 0 M W W 0 M W W a M W W 0 M W W 0 M ~ ~ ~ ~ N N N N M M M M ~ ~ ~ ~ W W W W W W W W ~ ~ ~ ~ W W W Hour Figure 8: Typical Daily (Week-Day) Seasonal Load Profiles by System and Control Area Summer Winter000 000 000 b 5 000 000 000 ---- 000 000 000 000 000 000 3: 5, 000 ~ 4 000 000 000 000 ----- -East -West -System -East -West -System 1 2 3 4 5 6 7 8 9 1011 12131415161718192021222324 Hour 1 2 3 4 5 6 7 8 9 1011 121314151617 18 192021222324 Hour Quantec PacifiCorp Demand Response Proxy Supply Curves Figure 9: Typical Daily (Week-Day) System Load Profiles by Sector 000 000 Winter 000 . 000 - ~ 4 000 000 ~~~ 000 000 : 0 .1 2 3 4 5 6 7 8 9 1011 12131415161718192021222324 Hour -System -TotaLSector -Residential 000 000 000 000 3: 5 000 :0 4 000 000 000 000 Summer ------ 123456789101112131415161718192021222324 Hour Commercial -Industrial -Irrigation 3. De.'elop sector- and segment-specific typical peak day load profiles for each end use. Typical" daily profiles are developed for each end-use within various market segments. Contributions to system peak for each end-use are estimated based on end-use shares available from PacifiCorp or regional estimates, available through EIA energy use surveys. Figure 10 and Figure 11 display the end-use contributions, summarized across sectors, to system load. Figure 10: End-Use Contributions to System Load- Summer 000 000 000 000 000 000 000 000 000 - -,-,..-...---,...,.-------. . 3 4 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Hour . q, .. --,.. wM. -'- '" ....... -System '-Lighting -Total Enduse -Heating-Process -Irrig Quantec PacifiCorp Demand Response Proxy Supply Curves Cooling -Waterheat ... "- Refrigeration-=--- Plug Figure 11: End-Use Contributions to System Load- Winter 000 000 000 000 000 000 000 000 ' --'~~--'"'!."" "' , c,"";. ",, ct="""""'ct~ "~""" -""'o' 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Hour -System Lighting -TotaLEnduse -Heating-Process -Irrig Cooling -Waterheat "'. ' Refrigeration -Plug 4. Estimate technical potential. Technical potential for each demand response strategy is assumed to be a function of customer eligibility in each class and the expected impact of the strategy on the targeted end-uses. Analytica11y, technical potential (TP) for demand- response strategy s is calculated as the sum of impacts at the end-use level ( e), generated in customer sector (c), by the strategy (s), that is: TP' IlP.ce and TP.ce es where LEes (load eligibility) represents the percent of customer class loads that are eligible for strategy s LIse (load impact) is percent reduction in end-use load resulting from strategy s Load eligibility (LEes) thresholds are established by calculating the percent of load by customer class and market segment that meet load criteria for each strategy. Table 8 outlines the portion of load that is eligible for program strategies. (Section V provides detailed program-specific assumptions. ) Estimates of maximum load impacts, resulting from various demand response strategies (LIse are derived from the commercial and industrial Enhanced Automation Study sponsored by the California Energy Commission studies by Lawrence Berkeley National Laboratories Quantec PacifiCorp Demand Response Proxy Supply Curves (e., Goldman, 2004), and the experiences of PacifiCorp and other utilities with similar DR programs. Table 9 outlines these inputs; detailed assumptions are found in the following section. Table 8: Eligibility by Sector and Program Fully Dispatchable . .... Scheduled Thermal CriticalProgramCurtailable DemandFil1Ti-Energy PeakName/Sector Winter Summer LargeC&1 .Rates Buyback ;. . Irrigation Storage Pricing Residential 100%100% - - -- - -- - - 100% Education - - -- - - 19% - - -- - - 50%100%50% Food Stores - - -- - - 27% - - -- - - 70%100%70% Hospitals - - -- - -- - -- - -- - - Hotels/Motels - - - 20% - - - 20%12%100%12% Other Health - - - 23% - - - 60%60% Miscellaneous - - -- - -- - -- - -- - - Offices - - - 10%19% - - - 10%50%100%50% Assembly - - - 10% - - - 10%20%20% Restaurants - - - 50% - - -- - - 50% Retail - - - 12% - - -- - - 12% Warehouses - - - 13%15% - - - 13%40%40% Industrial - - -- - - 30% - - -- - - 80%100%80% Irrigation - - -- - - 19%100% - - - 50% Eligibility Residential Residential LargeC&I- . . ;;.Irrigation Small Large C&I-No Load Large C&I - Criteria and Small . ~250 only Commercial ~250kW Threshold ~250kW Commercial withEMS ; (-==30kW) . .; . Table 9: Technical Load Impacts Fully Dispatchable Scheduled Thermal CriticalProgramCurtailable DemandFirm-Energy PeakName/Sector Winter Summer Large C&I Rates Buyback . . Irrigation Storage Pricing End Use Space Htg Hot Water Cooling Total PrOcess Cooling Total Total Total Residential 90%90%90% - - -- - -- - -- - - 25% - -- Education - - -- - -- - - 22% - - -- - - 22%25%22% Food Stores - - -- - -- - - 20% - - -- - - 20%25%20% Hospitals - - -- - -- - -- - -- - -- - -- - -- - -- - - Hotels/Motels - - -- - - 90%20% - - - 90%20%25%20% Other Health - - -- - - 90% - - - 90% - - - Miscellaneous - - -- - -- - -- - -- - -- - -- - -- - -- - - Offices - - -- - - 90%32% - - - 90%32%25%32% Assembly - - -- - - 90%20% - - - 90%20% - - - 20% Restaurants - - -- - - 90% - - -- - - 90% - - -- - -- - - Retail - - -- - - 90% - - -- - - 90% - - -- - -- - - Warehouses - - -- - - 90%30% - - - 90%30% - - - 30% Industrial - - -- - -- - - 30% - - -- - - 30%25%30% Irrigation - - -- - -- - - 30%90% - - - 30% - - - 30% Quantec PacifiCorp Demand Response Proxy Supply Curves Methodology for Estimating Market Potential Market potential is the subset of technical potential that may reasonably be implemented, taking into account the customers ' ability and willingness to participate in load reduction programs subject to their unique business priorities, operating requirements, and economic (price) considerations. Market levels of potential are derived by adjusting technical potentials by two factors: expected rates of program and event participation. Market potential (MP) is calculated as the product of technical potential, sector program participation rates (PPc ), and expected event participation (EPe rates: AlP. TP'c Rates of program and event participation are estimated based on the recent experiences of PacifiCorp and other utilities, as well as those of Regional Transmission Organizations (RTOs) that have offered similar programs. Table 10 outlines the estimates of program and event participation; referenced assumptions are found Section V. Table 10: Program and Event Participation Inputs Fully Dispatchable . Scheduled Thermal Curtailable Critical DemandLargeFirm-Energy PeakWinterSummerRates Buyback C&I Irrigation S~orage .. Pricing Program Participation 10%20%*50%20%25%35% Event Participation 100%100%90%50%100%90%90%13% * Represents residential sector; commercial sector is assumed to be 5% Utility customers ' willingness to participate in DR programs (or "market potential") is itself a function of price and non-price factors. Non-price factors generally depend on specific operational constraints that may impede participation in DR. These are generally difficult to quantify and may only be determined through rigorous market studies. Price-induced effects, particularly for market-based DR strategies, can, however, be estimated explicitly by calculating price elasticity of load response, based on empirical data, using the following general formulation of price elasticity: LogN(MW) j3 LOG(P), where AI". is the quantity of demand reduction commitment during each curtailment event and represents the offer prices (incentives) from the utility. Since the equation is specified in logarithmic form fJ is a direct measure of elasticity, indicating percent change in load commitment that may be expected to result from a one percent change in incentives. Quantec PacifiCorp Demand Response Proxy Supply Curves To estimate the parameters ofthe above model, data were collected on the 2000-2001 experience of four major utilities in the Northwest (PacifiCorp, PSE, PGE, and Avista) on their demand buyback programs. The estimated parameters of the model are shown below. LogN(MW) = - 0.5 + 1.45 (3.0) LogN(P) The calibration of the demand model resulted in a price coefficient of 1.45 with a t-statistic of , indicating that the estimated coefficient is statistically significant at the 95% level of significance or better. The estimated parameter for the price variable shows that for every one percent change in price, load response is expected to change by 1.45%, indicating a moderately elastic response. The statistical parameters of the estimated model are shown in Table 11 , below. Table 11. Estimation Results of the Elasticity Model Variable Estimated Parameter Statistic Intercept (0) LogN (Price)1.45 Number of Observations: 13 R2 = 0. The elasticity estimate obtained from the data is higher than expected. There have not, however been any other studies of response elasticity for demand buyback or demand biding programs. Additionally, slight changes in the specification of the above quantity/price relationship, introduced by using alternative data frequency levels, such as daily or monthly, are likely to alter the parameter estimates. For example, daily, event-by-event data, available from Puget Sound Energy for 2000-2001 , resulted in a significantly lower elasticity of 0.45. Unfortunately, event- by-event data were not available for an four utilities. Such data, we expect, would likely have produced a more robust and reliable estimate of price elasticity for demand buyback programs. Development of Cost Estimates Demand response strategies vary significantly with respect to both type and level of costs. Applicable resource acquisition costs for DR generany fan into two categories: 1) fixed direct expenses such as infrastructure, administration, and data acquisition; and 2) variable costs ( i. incentive payments to participants). For this project, cost estimates are based on the experiences ofPacifiCorp and other utilities, as wen as RTOs offering various DR programs. Fixed Costs. Fixed costs vary significantly across various DR resource acquisition programs and depend, to a large extent, on program design. For example, implementation of some market- based programs, such as demand buyback, may require up-front investments in communication and data acquisition infrastructures, while tariff-based programs may be implemented at a relatively low cost to the utility. Quantec PacifiCorp Demand Response Proxy Supply Curves Variable Costs. Estimation and treatment of variable costs, particularly in the case of market- based programs poses a much greater chal1enge in determining the price component of the supply curve as, clearly, these will have a direct effect on the quantity of resources that are available. As described above, elasticity estimates were used to account for these impacts. Table 12 outlines the development (up-front investment) and annual costs for the three categories of cost inputs: per-kW/year, per-customer, and program administration. Incentive payments for large commercial and industrial customers are often paid on a per-kW basis. On a per-customer basis, development costs typically include control hardware, instal1ation, and marketing costs; annual costs include maintenance and incentives. Program costs were assumed to be relatively consistent across all programs - $300 000 to begin a new program, $150 000 to expand existing programs 10; $100 000 in ongoing administrative cost Table 12: Cost Inputs Cost Typel Fully Dispatchable Scheduled Thermal Curtailable Critical DemandLargeFirm-Energy PeakFrequencyWinterSummerlrrigation .Rates Buyback C&I Storage Pricing per kW-year Development - - -- - -- - -- - -- - -- - -- - -- -- Annual - - -- - - $48 $10 $105 $48 - - - $10 per Customer-year (including meter costs) Development $320 $320 200 $700 - - - 200 $500 $700 Annual $112 $55 - - - $1,000 - - -- - - $50 - - - Program $300 Development $300 000 $150 000 $150,000 $300 000 $300 000 $300,000 $150 000 $100 Annual $100 000 $100 000 $600 000 $100,000 $100,000 $100 000 $100 000 These costs are al1ocated to each year of the planning horizon, based on: CostsSY $Pgmdyl $Pgm ($kW ($Customer Part ($Customer Part 10 PacifiCorp Energy Exchange (2001) spent over $200 000 in initial costs. TaU (2001) had initial costs of $341 000, including load research. II Energy Exchange (2005) spends $72 000 annually in external vendor costs (not including PacifiCorp administrative costs), Idaho Irrigation Pilot (2005) spent $55 000 in program management, TaU had ongoing costs of$155 000 (2002) and $110 000 (2003). Quantec PacifiCorp Demand Response Proxy Supply Curves Where Costssy are the costs for a program strategy s in year $Pgmdyl are the program development costs in year 1 only $Pgm a are the annual program costs $kWa are the annual costs on a per kW basis (Table 12) is the amount of kW potential in year y. This study uses a three-year ramping, such that one-third of the achievable potential, shown in Table 4, is added in each of the first three program years. The quantity in subsequent years increases at the same rate as sales. $Customer d are per-customer development costs Part yo is the number of new participants in the program in year y $Customera is the annual cost per customer Part is the number of total participants in the program, as a function of PartkW, which is the kW impact per customer, as shown in Table 13 (program-level assumptions found in Section V). Part Part Table 13: Load Impact per Customer (kW) Program Fully Dispatchable Scheduled Thermal Curtailable Critical.Demand Name/Sector Winter Summer LargeC&1 Finn -Energy Rates Peak BuybackIrrigation.Storage Pricing Residential - - -- - -- - -- - -- - - Education - - -- - - 124 - - -- - - 124 124 Food Stores - - -- - - 134 - - -- - - 134 134 Hospitals - - -- - -- - -- - -- - -- - -- - - Hotels/Motels - - - 104 - - -- - - 104 104 Other Health - - -- - -- - -- - - Miscellaneous - - -- - -- - -- - -- - -- - -- - -- - - Offices - - - 221 - - -- - - 221 221 Assembly - - - 230 - - -- - - 230 - - - 230 Restaurants - - -- - -- - -- - -- - -- - -- - - Retail - - -- - -- - -- - -- - -- - -- - - Warehouses - - - 173 - - -- - - 173 - - - 173 Industrial - - -- - - 531 - - -- - - 531 531 Irrigation - - -- - -- - -- - -- - -- - -- - - Quantec PacifiCorp Demand Response Proxy Supply Curves Resource Interaction Estimates The final step in supply curve development is to estimate the amount of market potential that is available for each program in the portfolio. Table 14 outlines the percent of market potential that is considered available, given the ranking of programs by levelized cost with consideration given to reliability. For example, 100% of demand buyback and scheduled firm irrigation is considered achievable. Although critical peak pricing is ranked next in levelized cost, it is another non-firm resource, so it becomes tertiary to curtailable rates. Curtailable rates and dispatchable large C&I compete for the same target market as DBB, therefore only 50% of their market potential will be available. The summer DLC program is the least expensive residential and small commercial control program. Therefore 100% of this program is available. Since the TES also targets the cooling loads (cool storage) as a secondary option, half of the TES potentials are assumed to be available. Table 14: Interaction (Percent of Market Potential Available) Fully Dispatchable Scheduled ThermalProgram Curtailable Critical Peak DemandLargeFirm-Energy Name/Sector Winter.Summer Rates .. . Pricil1g"Buy.backC&I . Irrigation Storage . .. ... . Residential 50%100% - - -- - -- - -- - - 20% - - - Education - - -- - - 50% - - -- - - 50%20%100% Food Stores - - -- - - 50% - - -- - - 50%20%100% Hospitals - - -- - -- - -- - -- - -- - -- - -- - - Hotels/Motels - - - 100%50% - - - 50%50%20%100% Other Health - - - 100%50% - - - 50%50% - - - 100% Miscellaneous - - -- - -- - -- - -- - -- - -- - -- - - Offices - - - 100%50% - - - 50%50%20%100% Assembly - - - 100%50% - - - 50%50% - - - 100% Restaurants - - - 100% - - -- - - 50% - - -- - -- - - Retail - - - 100% - - -- - - 50% - - -- - -- - - Warehouses - - - 100%50% - - - 50%50% - - - 100% Industrial - - -- - - 50% - - -- - - 50%20%100% Irrigation - - -- - - 50%100% - - - 50% - - -- -- Quantec PacifiCorp Demand Response Proxy Supply Curves Detailed Program Assumptions Table 15. Fully Dispatchable - Winter Portland General Electric Space and Water Heating Direct Load Control Program; Programs Researched Pennsylvania, New Jersey, Maryland ISO water heating; Florida Power & Light Residential On Call program; Puget Sound Energy Home Comfort Control Thermostat; Hawaiian Electric Residential Hot Water; Wisconsin Public Services DLC Load Basis Average of top 87 winter hours Development: Customer - $300 for control equipment and labor, $200 for meter and installation labor (PGE - Quantec 2003) but installed for only 10% of participants, $300 000 Basis torCost Calculations for program development; Annual: $30 in maintenance, $9 (1.5/month for 6 months) in communications, $72 ($12/month for 6 months - both water heating and space) in incentives, and $100 000 annual program administration. High assumes incentives are increased ($15/month - $90), low is half incentive ($6/mth- High/Low Cost Notes $36). Annual program administrative costs are increased by $50 000 in high case and reduced by $50,000 in low case. Technical Potential Less than complete technical ability to cycle different technologies (90%) and 50% cycling strategy; therefore 45% Eligible Load (0/0)Residential space heating and water heating . High is based on 20% participation of FPL On Call program, base (10%) closer to Duke Program Participation (0/0)program of 13% (Duke - Quantec 2005), and low (5%) represents low program participation (DOE - 2006) Event Participation (0/0)100% Current Program (kW) Per-Customer Impacts (kW)2kW estimate per participant based (PSE, Quantec 2003) - includes cycling strategy Hours Per Month 3 hours in January; 84 hours in December (based on the distribution of the PacifiCorp 2005 system profile) Quantec PacifiCorp Demand Response Proxy Supply Curves Load Basis High/Low Cost Notes Technical Potential Eligible Load (%) Program Participation(%) Event Participation (%) Current Program (kW) Per-Customer Impacts (kW) Hours Per Month Table 16. Fully Dispatchable - Summer Florida Power & Light Residential On Call & Business On Call; SCE Large Business Summer Discount Plan; Wisconsin Public Services; Duke Residential AC Program PacifiCorp and MidAmerican Average of top 87 summer hours Development: Customer - $300 for control equipment and labor, $200 for meter and installation labor (PGE - Quantec 2003) but installed for only 10% of participants, $300 000 for program development; Annual: $30 in maintenance, $4.5 (1.5/month for 3 months) in communications, incentives - $20 (3 months at $7/month - PSE pays $6, Duke $8, PAC $7), and $100 000 annual program administration High assumes incentives are doubled ($40), low is half incentive ($10). Annual program administrative costs are increased by $50 000 in high case and reduced by $50 000 in low case. Less than complete technical ability to cycle different technologies (90%) and 50% cycling strategy; therefore 45% Cooling load for residential and portion of commercial load that is less than 30 kW (PacifiCorp - Quantec 2003) Assumes 20% residential and 5% small commercial (FP&L -13% small C&I participation 19% residential, PAC Utah Cool Keeper 27% residential and -0% commercial), high assumes that 5% more program participation is possible , low assumes 5% less 100% 65 MW of load reduction in Utah Cool Keeper Program on Dispatch mode Impact: Cooling - 1.5 kW for residential , 2.0 kW for small com, DOE 2006, Quantec 2003 June 8, July 54; August 32 - adjusts 2005 System load to account for experience program dispatch by Cool Keeper Quantec PacifiCorp Demand Response Proxy Supply Curves Programs Researched Load Basis Technical Potential Eligible Load (%) Program Participation (%) EventParticipation (%) Current Program (kW) Per-Customer Impacts (kW) Hours Per Month Table 17. Fully Dispatchable - Large C&I Florida Light & Power C&I On Call; Hawaiian Electric Large Commercial; Wisconsin Public Services DLC; Southern California Edison Large Business Summer Discount Plan Average of top 87 summer hours Development: Per customer of $500 for targeted marketing and $700 for meter (Duke - Quantec 2005); $300,000 for program development, $100 000 annual program administration. Per kW costs assume $8/month for 3 months (double the incentive as curtailable rates but for fewer months) High incentive is $14/month and low is $6/month (again, double curtailable rates incentive; see curtailable rates for references) Annual program administrative costs are increased by $50 000 in high case and reduced by $50 000 in low case. Total curtailable load based on Goldman (2004)- National Trends, by sector. If not mentioned, unclassified was used. Using portion of cooling load that is greater than 250 kW as eligible (PacifiCorp - Quantec 2003) and assuming only 38% with EMS systems (CBSA 05) Participation - Florida Power And Light C&I On Call has less than 1 % of all customers. Because our figures already account for those not eligible, we have assumed 3% base 8% high, and 1% low. 90% Per customer impacts are calculated as product of average load for customers ::-250 kW and the technical potential above June 8, July 54; August 32 - adjusts 2005 System load to account for experience in program dispatch by Cool Keeper, assuming that system decisions to curtail residential customers would be similar for C&I customers Quantec PacifiCorp Demand Response Proxy Supply Curves Variable Cost $/MWh Table 18. Scheduled Firm - Irrigation BPA Irrigation , Idaho Power, PacifiCorp Average of entire summer on-peak period Development: $700 installed cost of advanced metering technologies; Idaho IRR: Annual: $10 per kW ($8.5 in 2005), $300 000 for program development, $100,000 annual program administration. Also includes $500K of additional expenditures committed in 2005 for ongoing programs by PacifiCorp. High cost doubles incentive; low assumes the same, Annual program administrative costs are increased by $50 000 in high case and reduced by $50 000 in low case. Less than complete technical ability to schedule reductions on all load (e., lift stations) Irrigation sector Program participation of 50% (2005 Idaho IRR - 100 MW signed up of 200 MW load) is assumed to be base. High and low has relatively tight band +/-5%. 50% event participation assumes participants sign up only for 2 out of 4 days (similar to PacifiCorp Idaho program) 48 MW from Idaho program Idaho reduction of 100 kW per customer reduced to 90 to account for smaller irrigators in other regions 100% taken due to relatively inexpensive cost and lack of competition with other programs. June - August 96 hours per month, September 48 hours per month (4 days per week, 6 hours per day) Basis for Cost Calculations PrograrrisResearched Based on RFP response to PacifiCorp, summarized for Quantec in "TES Overview Load Basis Average of entire summer on-peak period Costs from "TES Overview" sent to Quantec on June 2, 2006 using per-kW costs by Basis for Cost Calculations external vendor, $300 000 for program development, $100 000 annual program administration Incentives remain constant, Annual program administrative costs are increased byHigh/Low Cost Notes $50 000 in high case and reduced by $50 000 in low case. Technical Potential Less than complete technical ability to use this technology (90%) on cooling load Eligibleload(%)Using portion of commercial cooling load that is less than 30 kW as eligible (PacifiCorp - Quantec 2003) Program Participation (%)20% program participation, with +/- 5% for high and low participation Event Participation (%)100% Current Program (kW) Per-Customer Impacts (kW) Hours Per Month 240 - April, 186 - May, 180 - June, 186 - July, 186 - August, 180 - September, 279 October Table 19. Thermal Energy Storage Quantec PacifiCorp Demand Response Proxy Supply Curves Programs Researched Load Basis Basis for Cost Calculations High/Low Cost Notes Technical Potential Eligible Load (%) Event Participation (%) Current Program (kW) Per-Customer Impacts (kW) Hours Per Month Table 20. Curtailable Rates Duke Interruptible Power Service; Georgia Power (Southern) Demand Plus Energy Credit; Duke Curtailable Service Pilot; Dominion Virginia Power Curtailable Service; MidAmerican; ConEd Interruptible/Curtailment Service, Southern California Edison C&I Base Interruptible Program, Wisconsin Average of top 87 summer hours Development: Per Customer of $500 for marketing and $700 for meter (Duke - Quantec 05); $300 000 for new program development, $100 000 annual program administration Base incentive of $48 ($4/kWMonth) (Pacific Gas and Electric pays $3-$7/kWMonth Southern California Edison pays $7/kWMonth, Wisconsin Power and Light pays $3.3/kWMonth, MidAmerican pays $3., Duke Power pays $3.5/kW-Month). Base incentive of $48 ($4/kWMonth) is increased by 50% in high case. Low assumes same incentive as base ($42). Annual program administrative costs are increased by $50,000 in high case and reduced by $50,000 in low case. Total curtailable load based on Goldman (2004)- National Trends, by sector. If not mentioned, unclassified was used. Using portion of load that is greater than 250 kW as eligible (PacifiCorp - Quantec 2003) National participation ranges from slightly greater than 0% (ISO NE) of customers to 30%, (NYISO 29%, Duke 14%). Base assumes 25% (due to load eligibility already accounted for), 5% more for high case and 12.5% less for low case. Event Participation reflects compliance rate (Duke - 90% + compliance, CEC - 90% + compliance Goldman (2002)) Per customer impacts are calculated as product of average load for customers =-250 kW and the technical potential above July 69; August 18 (based on the distribution of the PacifiCorp 2005 system profile) Quantec PacifiCorp Demand Response Proxy Supply Curves Table 21. Critical Peak Pricing Programs Researched Gulf Power GoodCents Select; Pacific Gas and Electric Critical Peak Pricing; Southern California Edison Critical Peak Pricing; San Diego Gas and Electric Critical Peak Pricing Load Basis Average of top 87 summer hours Development: Customer: $500 for advanced metering technologies; Program - $300 000 for new program development; Annual: Customer - $20 for meter reading, extra mailing, Basis for Cost Calculations and messaging (PSE - Quantec (2004)), $30 to account for the rate and energy benefits to the customer (Quantec PacifiCorp TOU (2005)) $100 000 annual program administration High/LowCost Note!;Annual program administrative costs are increased by $50 000 in high case and reduced by $50 000 in low case. Range of impacts from high 41 % (Gulf Power super peak) to 18% (Piette, 2006), Technical Potential therefore assume low-mid-point of 25%, (other relevant references - McAulife (2004) DOE 2006) Eligible Load (%)Eligibility- all customers assumed to be eligible except those deemed unable to respond (based on sectors reported in Quantum (2004)) Current programs in nation have very low participation (reviewed seven programs Program Participation (%)McAulife (2004) and Gulf Power with maximum of 3% - PG&E commercial program) - base is 3%, low is 0.5% and high is 5. EventParticipation(%) Event participation assumed to be less than all- Le., 90% Current Program (kW) Per-Customer Impacts (kW)Per customer impacts are calculated as product of average load for customers ::-250 kW and the technical potential above Hours Per Month July 69; August 18 (based on the distribution of the PacifiCorp 2005 system profile) Table 22. Demand Buyback Pacific Gas and Electric Demand Buyback (Commercial and Industrial); Southem Programs Researched California Edison Demand Buyback (Commercial and Industrial); San Diego Gas and Electric Demand Buyback; New York ISO Day Ahead Demand Response, PacifiCorp Load Basis Average of top 175 summer hours Development: $700 for advanced meter; Program development cost of $150 000 for Basis for Cost CalcUlations expansion; $100 000 annually for program administration. Incentive of $10/kW consistent with 2005 PacifiCorp Integrated Resource Plan base prices of $60/MWh High and low incentive levels are consistent with 2005 PacifiCorp Integrated Resource High/Low Cost Notes Plan base prices of $40/MWh (low) and $100/MWh (high). Annual program administrative costs are increased by $50 000 in high case and reduced by $50 000 in low case. Technical Potential Total curtailable load based on Goldman (2004)- National Trends, by sector. If not mentioned, unclassified was used. Eligible Load(%) Using portion of load that is greater than 250 kW as eligible (PacifiCorp - Quantec 2003) Range of program participation is from 0-6% (various California utilities - Quantum Program Participation (%) (2004)) to 17-25% (PJM/NYISO - Goldman (2004)). This study uses 35% to account for the eligibility correction for those ::-250 kW. High is 30%, low is 5% Event Participation(%)Event participation calculated from 2001 Northwest demand bidding experience Current Program (kW)1 MW of participation (165 MWh over 15 events, 10 hours per event) Per-Customer Impacts (kW)Per-customer impacts are calculated as product of average load for customers ::-250 kW and the technical potential above Hours Per Month July 129; August 46 (based on the distribution of the PacifiCorp 2005 system profile) Quantec PacifiCorp Demand Response Proxy Supply Curves VI.References Awerbuch, S. , " The Surprising Role of Risk and Discount Rates in Utility Integrated-Resource Planning," The Electricity Journal, Vol. 6, No., (April), 1993 20-33. Awerbuch, S., Portfolio-Based Electricity Generation Planning: Policy Implications for Renewables and Energy Security, Tynda11 Centre Visiting Fellow, SPRU-University of Sussex, Brighton, UK, 2005. Barbose, G., Goldman, and Neenan, B., Survey of Utility Experience with Real -Time Pricing, Lawrence Berkeley National Laboratory LBNL - 54238, December 2004. Bolinger, M. and R. Wiser. 2005. "Balancing Cost and Risk: The Treatment of Renewable Energy in Western Utility Resource Plans." LBNL-58450. Berkeley, Calif.: Lawrence Berkeley National Laboratory. http://eetd.1bLgov/ea/ems/reports/58450.pdf. Braithwait, S. and A. Faruqui , " The Choice Not to Buy: Energy $avings and Policy Alternatives for Demand Response Public Utilities Fortnightly 139(6),, March 15 2003; and Taylor Moore , " Energizing Customer Demand Response in California EPRI Journal Summer 2001 , p. 8. California Energy Commission. Enhanced Automation Technical Options Guidebook. 2003. California Standard Practice Manual -- Economic Analysis Of Demand-Side Programs And Projects California Public Utilities Commission October 2001. www . cpuc. ca. gov / stati c/ energy / electric/ energy+efficiency /rulemaking/resource5 .doc CPUC. O2-06-001 Third Report of Working Group on Dynamic Tariff and Program Proposals: Addendum Modifying Previous Reports January 16 2003 - California Public Utilities Commission Order Instituting Rulemaking on Policies and Practices for Advanced Metering, Demand Response, and Dynamic Pricing. Cowart, R.Efficient Reliability: The Critical Role of Demand-Side Resources in Power Systems and Markets National Association of Regulatory Utility Commissioners, Washington , June 2001. Department of Energy. Benefits of Demand Response in Electricity Markets and Recommendations for Achieving Them: A Report to the United States Congress Pursuant to Section 1252 of the Energy Policy Act of2005, U.S. DOE, February 2006. Goldman, Charles. Demand Response National Trends: Demand Response National Trends: Implications for the West? Committee on Regional Electric Power Cooperation Lawrence Berkeley National Laboratories, 2004. Goldman, Charles and , N. Hopper, O. Sezgen, M. Moezzi and R. Bharvirkar. Customer Response to Day-ahead Wholesale Market Electricity Prices: Case Study of RTP Quantec PacifiCorp Demand Response Proxy Supply Curves Program Experience in New York. Ernest Orlando Lawrence Berkeley National Laboratory, 2004. Goldman, Charles and Michael Kintner-Meyer. Value of Demand Responsive Load. E. O. Lawrence Berkeley National Laboratory, January, 2004. Goldman, Charles. Value of Demand Responsive Load. Ernest Orlando Lawrence Berkeley National Laboratory, 2004. Heffner, G., M. Moezzi and C. Goldman. Independent Review of Estimated Load Reductions for PJM's Smal1 Customer Load Response Pilot Project. Ernest Orlando Lawrence Berkeley National Laboratory, 2004 Hirst, Eric and B. Kirby, Retail-Load Participation in Competitive Wholesale Electricity Markets Edison Electric Institute, Washington, DC, January 2001. Hirst, Eric. Price-Responsive Demand as Reliability Resources, Oak Ridge, Tennessee 37830 April 2002. McAuliffe, Pat and Arthur Rosenfeld. Response of Residential Customers to Critical Peak Pricing and Time-of-Use Rates during the Summer of 2003. California Energy Commission, September, 2004. Neenan Associates. "NYISO 2003 Demand Response Program Evaluation , NYISO 2004. Neenan, Bernie, IssueAlert, UtiliPoint(ID International, Inc. 2006 Piette, Mary Ann and Sila Kiliccot. Characterization and Demonstration of Demand Responsive Control Technologies and Strategies in Commercial Buildings. Lawrence Berkeley National Laboratory. March, 2006 Peak Load Management AHiance. "Demand Response: Principles for Regulatory Guidance Peak Load Management Al1iance, February 2002. PG&E. Final Opinion on Application of Pacific Gas and Electric Company for Authority to Increase Revenue Requirements to Recover the Costs to Deploy an Advanced Metering Infrastructure (U 39 E), Application 05-06-028 (Filed June 16 2005). Quantec, LLC. Analysis of the Load Impacts and Economic Benefits of the TOU Rate Option. Pacific Power, 2005 Quantec, LLC. Assessment of Technical and Achievable Demand-Side Resource Potentials. Puget Sound Energy, 2005 Quantec, LLC. Assessment of Demand Response Resource Potentials for PGE and Pacific Power, 2003 Quantec PacifiCorp Demand Response Proxy Supply Curves RL W Analytics and Neenan Associates. "An Evaluation of the Performance of the Demand Response Programs Implemented by ISQ-NE in 2005", ISO-NE December 2005. RL W Analytics, Inc., Program Impact Evaluation of the 2004 SCE Energy$mart ThermostatSM Program. Southern California Edison, January 2005. Rocky Mountain Institute. Demand Response: An Introduction, Rocky Mountain Institute Boulder Colorado, April 30, 2006. Ruff, Larry. "Economic Principles of Demand Response in Electricity", Edison Electric Institute October 2002. Sezgen, Osmon, C. Goldman, and P. Krishnarao. "option Value of Demand Response , " Lawrence Berkeley National Laboratory, LBNL-6570, October 2005. Violette, D. DRR "Valuation and Market Analysis " Volume I, IEA, January 2006 Quantec PacifiCorp Demand Response Proxy Supply Curves Appendix A:East Region Results Table 23: Technical Potential (MW), East Fully Dispatchable Scheduled Thermal CriticalCurtailable DemandSectorWinterSummerLargeFirm-Energy Rates Peak Buyback C&I Irrigation Storage Pricing Industrial - - -- - - 143 - - -- - - 377 392 368 Commercial - - -- - - 134 Irrigation - - -- - -- - - 254 - - -- - -- - -- - - Residential 163 318 - - -- - -- - -- - - 342 - - - Total 163 353 173 254 455 868 444 % of East Peak 17% Table 24: Market Potential (MW), East Fully Dispatchable . . Sc~eduled Thermal Curtailable Critical DemandSectorLargeFirm...,Energy PeakWinterSummerC&I Irrigation Storage .Rates Pricing Buyback Industrial - - -- - -- - -- - - Commercial - - -- - - Irrigation - - -- - -- - -- - -- - -- - -- - - Residential 111 - - -- - -- - -- - -- -- Total 113 102 % of East Peak 0.4% Table 25. Achievable Potential (MW) and Costs, East Fully Dispatchable Scheduled Thermal Curtailable Critical Demand Winter Summer Large Firm-Energy Rates Peak Buyback Total C&I Irrigation Storage Pricing Resource Costs $76 $59 $82 $28 $117 $50 $46 $14($/kW/yr) - - - Achievable Potential 113 51 .276 Potential Net of 163Current Programs Quantec PacifiCorp Demand Response Proxy Supply Curves $125 $100 tI)- $75 $50 C1) :::- C1)..J $25 Figure 12: Cumulative Supply Curve, East 8 Critical Peak 8Curtailable II Irrigation 8 OBB ""'"...... Cumulative MW Quantec PacifiCorp Demand Response Proxy Supply Curves ...... 8 OLC Summe ""'".................. Appendix B: West Region Results Table 26. Technical Potential, West Fully Dispatchable .... Scheduled Thermal Critical Demand Sector Large Firm-Energy Curtailable PeakWinterSummerC&I Irrigation Storage Rates Pricing.Buyback . .. .. . Industrial - - -- - -- - -- - - 133 138 132 Commercial - - -- - - Irrigation - - -- - -- - - 128 - - -- - -- - -- - - Residential 210 - - -- - -- - -- - - 275 - - - Total 210 128 187 512 185 % of West Peak 16% Table 27. Market Potential, West Fully Dispatchable Scheduled .Thermal Curtailable Critical Peak DemandSectorLargeFirm-. EnergyWinterSummer Rates Pricing Buyback C&I Irrigation .Storage ' . Industrial - - -- - -- - -- - - Commercial - - -- - - Irrigation - - -- - -- - -- - -- - -- - -- - - Residential - - -- - -- - -- - -- - - Total % of West Peak 0.4% Table 28. Achievable Potential (MW) and Costs, West Fully Dispatchable Scheduled Thermal Curtailable Critical DemandLargeFirm-Energy Peak TotalWinterSummerRatesBuyback C&I Irrigation Storage Pricing . . Resource Costs ($/kW/yr)$76 $58 $89 $29 $119 $50 $63 $15 - - - Achievable Potential Potential Net of Current Programs Quantec PacifiCorp Demand Response Proxy Supply Curves Figure 13: Supply Curve, West $150 $125 $100 $75 !::! $50 ;)0 ...J $25 . OBB C\I lIlryigation "'" .. m Thermal Storage . OLC C&I mm ... OLC Winter. Cpp - . OLe Summer Critical Peak Cumulative MW Quantec PacifiCorp Demand Response Proxy Supply Curves ...... C\I ...... Ap p e n d i x C: D a t a P r o v i d e d to IR P Fi g u r e 1 4 : E a s t R e g i o n , R e f e r e n c e C a s e Va r i a b l e C o s t s ( $ / M W h ) Ma r k e t P r i c e s De m a n d R e d u c t i o n P e r i o d ( H o u r s ) St a r t Y e a r 00 9 00 9 00 9 00 9 00 9 00 9 00 9 00 9 11 3 11 7 15 9 11 5 13 1 10 1 11 8 Ho u r s A v a i l a b l e b y M o n t h Ja n u a r y Fe b r u a r y Ma r c h Ap r i l 24 0 Ma y 18 6 Ju n e 18 0 Ju l y 18 6 12 9 Au g u s t 18 6 Se p t e m b e r 18 0 Oc t o b e r 27 9 No v e m b e r De c e m b e r l Qu a n t e c Pa c i f i C o r p D e m a n d R e s p o n s e P r o x y S u p p l y C u r v e s Fi g u r e I S : W e s t R e g i o n , R e f e r e n c e C a s e Va r i a b l e C o s t s ( $ / M W h ) Ma r k e t P r i c e s De m a n d R e d u c t i o n P e r i o d ( H o u r s ) St a r t Y e a r 00 9 00 9 00 9 00 9 00 9 00 9 00 9 00 9 11 9 18 5 11 6 14 4 10 4 12 1 Ho u r s A v a i l a b l e b y M o n t h Ja n u a r y Fe b r u a r y Ma r c h Ap r i l 24 0 Ma y 18 6 Ju n e 18 0 Ju l y 18 6 12 9 Au g u s t 18 6 Se p t e m b e r 18 0 Oc t o b e r 27 9 No v e m b e r De c e m b e r Qu a n t e c Pa c i f i C o r p D e m a n d R e s p o n s e P r o x y S u p p l y C u r v e s Fi g u r e 1 6 : S y s t e m , R e f e r e n c e C a s e Va r i a b l e C o s t s ( $ / M W h ) Ma r k e t P r i c e s De m a n d R e d u c t i o n P e r i o d ( H o u r s ) St a r t Y e a r 00 9 00 9 00 9 00 9 00 9 00 9 00 9 00 9 12 0 11 8 16 7 11 5 14 1 11 4 10 2 11 9 Ho u r s A v a i l a b l e b y M o n t h Ja n u a r y Fe b r u a r y Ma r c h Ap r i l 24 0 Ma y 18 6 Ju n e 18 0 Ju l y 18 6 12 9 Au g u s t 18 6 Se p t e m b e r 18 0 Oc t o b e r 27 9 No v e m b e r De c e m b e r Qu a n t e c Pa c i f i C o r p D e m a n d R e s p o n s e P r o x y S u p p l y C u r v e s Fi g u r e 1 7 : E a s t R e g i o n , N o D B B Va r i a b l e C o s t s ( $ / M W h ) De m a n d R e d u c t i o n P e r i o d ( H o u r s ) St a r t Y e a r 00 9 00 9 00 9 00 9 00 9 00 9 00 9 11 3 10 2 11 7 15 9 11 5 13 1 12 5 10 1 11 8 Ho u r s A v a i l a b l e b y M o n t h Ja n u a r y Fe b r u a r y Ma r c h Ap r i l 24 0 Ma y 18 6 Ju n e 18 0 Ju l y 18 6 Au g u s t 18 6 Se p t e m b e r 18 0 Oc t o b e r 27 9 No v e m b e r De c e m b e r Qu a n t e c Pa c i f i C o r p D e m a n d R e s p o n s e P r o x y S u p p l y C u r v e s Fi g u r e 1 8 : W e s t R e g i o n , N o D B B Va r i a b l e C o s t s ( $ / M W h ) De m a n d R e d u c t i o n P e r i o d ( H o u r s ) St a r t Y e a r 00 9 00 9 00 9 00 9 00 9 00 9 00 9 11 9 18 5 11 6 14 4 10 4 12 1 Ho u r s A v a i l a b l e b y M o n t h Ja n u a r y Fe b r u a r y Ma r c h Ap r i l 24 0 Ma y 18 6 Ju n e 18 0 Ju l y 18 6 Au g u s t 18 6 Se p t e m b e r 18 0 Oc t o b e r 27 9 No v e m b e r De c e m b e r Qu a n t e c Pa c i f i C o r p D e m a n d R e s p o n s e P r o x y S u p p l y C u r v e s Fi g u r e 1 9 : S y s t e m , N o D B B Va r i a b l e C o s t s ( $ / M W h ) De m a n d R e d u c t i o n P e r i o d ( H o u r s ) St a r t Y e a r 00 9 00 9 00 9 00 9 00 9 00 9 00 9 12 0 14 4 11 8 16 7 11 5 14 1 11 4 17 7 10 2 11 9 Ho u r s A v a i l a b l e b y M o n t h Ja n u a r y Fe b r u a r y Ma r c h Ap r i l 24 0 Ma y 18 6 Ju n e 18 0 Ju l y 18 6 Au g u s t 18 6 Se p t e m b e r 18 0 Oc t o b e r 27 9 No v e m b e r De c e m b e r Qu a n t e c Pa c i f i C o r p D e m a n d R e s p o n s e P r o x y S u p p l y C u r v e s Fi g u r e 2 0 : E a s t R e g i o n , N o M e t e r i n g Va r i a b l e C o s t s ( $ / M W h ) Ma r k e t P r i c e s De m a n d R e d u c t i o n P e r i o d ( H o u r s ) St a r t Y e a r 00 9 00 9 00 9 00 9 00 9 00 9 00 9 00 9 11 3 11 7 15 9 11 5 13 1 10 1 11 8 Ho u r s A v a i l a b l e b y M o n t h Ja n u a r y Fe b r u a r y Ma r c h Ap r i l 24 0 Ma y 18 6 Ju n e 18 0 Ju l y 18 6 12 9 Au g u s t 18 6 Se p t e m b e r 18 0 Oc t o b e r 27 9 No v e m b e r De c e m b e r Qu a n t e c Pa c i f i C o r p D e m a n d R e s p o n s e P r o x y S u p p l y C u r v e s Fi g u r e 2 1 : W e s t R e g i o n , N o M e t e r i n g Va r i a b l e C o s t s ( $ / M W h ) De m a n d R e d u c t i o n P e r i o d ( H o u r s ) St a r t Y e a r 00 9 00 9 00 9 00 9 00 9 00 9 00 9 11 9 18 5 11 6 13 6 10 4 12 1 Ho u r s A v a i l a b l e b y M o n t h Ja n u a r y Fe b r u a r y Ma r c h Ap r i l 24 0 Ma y 18 6 Ju n e 18 0 Ju l y 18 6 12 9 Au g u s t 18 6 Se p t e m b e r 18 0 Oc t o b e r 27 9 No v e m b e r De c e m b e r Qu a n t e c Pa c i f i C o r p D e m a n d R e s p o n s e P r o x y S u p p l y C u r v e s Fi g u r e 2 2 : S y s t e m , N o M e t e r i n g Va r i a b l e C o s t s ( $ / M W h ) $ Ma r k e t P r i c e s De m a n d R e d u c t i o n P e r i o d ( H o u r s ) St a r t Y e a r 00 9 00 9 00 9 00 9 00 9 00 9 00 9 00 9 12 0 11 8 16 7 11 5 14 1 11 4 10 2 11 9 Ho u r s A v a i l a b l e b y M o n t h Ja n u a r y Fe b r u a r y Ma r c h Ap r i l 24 0 Ma y 18 6 Ju n e 18 0 Ju l y 18 6 12 9 Au g u s t 18 6 Se p t e m b e r 18 0 Oc t o b e r 27 9 No v e m b e r De c e m b e r Qu a n t e c Pa c i f i C o r p D e m a n d R e s p o n s e P r o x y S u p p l y C u r v e s PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results APPENDIX C - DETAILED CEM MODELING RESULTS This appendix presents detailed Capacity Expansion Module (CEM) results for the 16 alternative future scenarios, 16 sensitivity analysis scenarios, and an additional set of sensitivity scenarios requested by public stakeholders. . '" . '", ALTERNA TIVEFUTUREAND SENSITIVITY ANAL YSIS SCENARIORESUETS . Table C.I - Alternative Future Scenarios .... OAF Coal Cost: CO2.Adde~/Coal Commodity Price onelMediu NonelLow NonelLow NonelLow High/High High/High High/High HighlMedium NonelMedium Business As Usual Low Cost Coal/High Cost Ga with Low Load Growth with High Load Growth igh Cost CoallLow Cost Ga with Low Load Growth with High Load Growth Favorable Wind Environment Unfavorable Wind Environment High DSM Potential Low DSM Potential Medium Load Growth Low Load Growth High Load Growth Low Cost Portfolio Bookend High Cost Portfolio Bookend High/Medium NonelMedium MediumlMedium MediumlMedium diumlMediu NonelLow High/High Table C.2 - Sensitivity Analysis Scenarios Gasl Electric Price Medium High High High Low Low Low High Low .,.. Renewable . ... Sal~s .' Ren~wable ' Load ,", Percent~g~P'fC DS1\i ' Growtb du~.to RPS A"a.iIabilityp(jtential Medium Low Yes Medium Medium Medium Yes MediumLow Medium Yes MediumHigh Medium Yes Medium Medium Medium Yes MediumLow Medium Yes MediumHigh Medium Yes Medium Medium High Yes Medium Medium Low No Medium Medium Medium Yes High Medium Medium Yes Low Medium Medium Yes MediumLow Medium Yes MediumHigh Medium Yes MediumLow Medium Yes MediumHigh Medium No Medium High Low Medium Medium Medium Low High SAS# . Nam~ .Basis . ' . Plan to 12% capacity reserve margin CAF #11 Plan to 18% capacity reserve margin CAF #11 CO2 adder implementation in 2016 CAF #11 Regional transmission project CAF #11 CO2 adder impact on resource selection: test $15, $20, $25 per ton adders CAF #11(approximately $10, $15, and $20 in 1990 dollars) Low wind capital cost CAF #11 High wind capital cost CAF #11 Low coal price CAF #11 High coal price CAF #11 Low IGCC capital cost CAF #11 High IGCC capital cost CAF #11 Replace a baseload pulverized resource with carbon-capture-ready IGCC CAF #11 Replace a baseload resource with IGCC/single gasifier CAF #11 Replace a base load resource with IGCC/sequestration CAF #11 Plan to "average of super-peak" load CAF #11 Favorable Wind Environment" scenario assuming pennanent expiration of the re . CAF07("Favorable newables PTC beginning in 2008 Wind Environment" PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results In the foUowing tables, fossil fuel resource additions are reported as nameplate megawatts ac- crued as of the year listed. Wind resources, unless noted otherwise, are reported as the estimated megawatt peak capacity contribution accrued as of the year listed. Table c.3 - Aggregate Resource Additions . . PYRR. Scenario (1f!illiO)1s)CAFOO $ 19 619CAFOI $ 18 071 CAF02 $ 11 022CAF03 $ 30 159 CAF04 $ 30 504 CAF05 $ 23 920CAF06 $ 40 002 CAF07 $ 33 339CAF08 $ 18 858CAF09 $ 33 213 CAF1O $ 19 002CAFll $ 24 606 CAF12 $ 17 689CAF13 $ 35 024CAF14 $ 13 689 CAF15 $ 49 234 SA SO 1 $ 24 400SAS02 $ 24 983SAS03 $ 22 673SAS04 $ 24 182 SAS05-1O $ 28 551 SAS05-15 $ 32 390 SAS05-20 $ 36 073SAS06 $ 24 282SAS07 $ 24 836SAS08 $ 24 401SAS09 $ 24 980 SAS1O $ 24 559SASll $ 24 660SAS12 $ 24 976SAS13 $ 24 980SAS14 $ 25 521SAS15 $ 24,412SAS16 $ 35 049 ;';';;"":..' 135 228 224 151 151 135 222 299 151 135 182 326 122 135 122 122 150 106 118 2008 2009748 722749 722423 210 106 1 271749 723424 211 107 1 271749 718747 721749 721749 723749 723423 211 105 1 268422 208 109 1 268471 436021 995748 722748 723749 722749 724748 720746 711748 723749 723749 723749 723748 721749 722748 722748 722516 476747 722 'R~~9IlrceAdditions(M.W) . " ., '' .,.// 2010' 2011 2012 2013 2014" . ' 2015 2016 236 1 523 2 677 2 980 3 238 3 306 3 585 237 1 526 2 692 3 173 3 153 3 236 3 509576 696 1 704 1 667 2 162 2 362 1 950 999 2 517 3 819 4 157 5 080 5 636 6 057 236 1 524 2 682 2 854 3 149 3 227 3 533576 695 1 670 1 661 1 722 1 638 1 730 996 2 515 3 840 4 247 4 711 5 152 5 644 236 1 520 2 692 2 887 3 183 3 258 3 535 235 1 521 2 679 2 803 3 112 3 203 3 512 236 1 524 2 697 2 878 3 140 3 233 3 540 237 1 525 2 682 2 805 3 112 3 203 3 508 238 1 524 2 673 2 838 3 126 3 209 3 510576 696 1 669 1 660 1 762 1 669 1 772 996 2 504 3 831 4 197 4 737 5 142 5 748574 694 1 653 1 639 1 776 1 687 1 788 001 2 511 3 838 4 259 4 917 5 172 5 745 954 1 231 2 356 2 690 2 940 3 008 3 172 527 1 826 3 013 3 187 3,465 3 562 3 918 236 1 519 2 693 2 979 3 237 3,303 3 584 236 1 522 2 694 3 174 3 150 3 257 3 543 237 1 523 2 673 2 845 3,115 3 211 3 509 237 1 524 2 673 2 791 3 103 3 200 3 501 236 1 514 2 651 2 812 3 081 3 175 3,488 240 1 528 2 706 2 872 3 166 3 242 3 546 236 1 523 2 697 2 865 3 242 3 318 3 595 237 1 524 2 702 3 184 3 159 3 245 3 560 238 1 524 2 703 2 991 3 245 3 315 3 525 237 1 524 2 684 3 173 3 123 3 208 3 505 235 1 523 2 697 2 865 3 242 3 318 3,595 236 1 524 2 684 2 897 3 153 3 247 3 558 233 1 520 2 698 2 905 3,181 3 270 3 573 236 1 522 2 683 2 896 3 152 3 248 3 558 000 1 282 2,417 2 584 2 851 2 934 3 228 236 1 523 2 693 2 874 3 296 3 320 3 572 100 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table CA - Wind Resource Additions I t MW)amep a e Scenario . . 2007 2008 2009 2010 2011 2012.2013.2014.2015 2016 CAFOO 300 300 300 300 300 300 300 300 300 300 CAFOI 600 800 800 800 800 000 000 000 000 000 CAF02 200 400 400 400 400 400 400 400 400 400 CAF03 000 300 300 300 300 400 400 400 1,400 400 CAF04 400 400 400 400 400 400 SOO SOO SOO 1 ,400 CAF05 200 300 300 300 300 300 300 600 600 400 CAF06 000 000 000 000 000 000 000 SOO 800 200 CAF07 800 000 100 100 100 200 200 200 800 100 CAF08 CAF09 800 000 000 000 000 600 600 300 100 100 CAFI0 400 400 400 400 400 400 400 400 400 400 CAFll 600 700 700 700 700 700 700 700 700 700 CAF12 200 300 300 300 300 400 400 400 400 400 CAF13 900 900 900 900 900 900 900 900 900 900 CAF14 200 300 400 400 400 400 400 400 400 400 CAF15 300 300 300 300 300 400 400 400 800 300 SASOI 400 SOO SOO SOO SOO 600 600 600 600 600 SAS02 400 400 1 ,400 l,400 400 1 ,400 1 ,400 400 SOO SOO SAS03 300 400 400 400 400 400 400 400 400 400 SAS04 400 SOO SOO SOO SOO SOO SOO SOO SOO 900 SAS05-800 900 900 900 900 900 100 100 200 200 SAS05-600 600 600 600 600 600 600 600 600 600 SAS05-100 200 200 200 200 900 900 900 900 800 SAS06 800 000 000 000 000 000 000 000 000 000 SAS07 300 300 300 300 300 300 400 400 400 500 SAS08 SOO SOO SOO SOO SOO SOO SOO 500 500 SOO SAS09 600 700 700 700 700 700 700 700 700 700 SASI0 SOO SOO SOO SOO SOO SOO SOO SOO SOO SOO SASll 300 400 400 400 400 400 400 400 400 400 SAS12 SOO 600 600 600 600 600 600 600 600 600 SAS13 600 700 700 700 700 700 700 700 700 700 SAS14 400 SOO SOO SOO SOO SOO SOO SOO SOO 900 SAS15 600 700 700 700 700 800 900 900 900 900 SAS16 200 200 400 600 800 000 200 SOO 700 900 101 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table C.5 - Front Office Transactions Figures shown are megawatts acquired in each year. Annual figures are not additive. Contract quantities were grossed up by the planning reserve margin to reflect the assumption that contract purchases are firm. Scenario":ZO07.2008 2009 2010.2011 2012 2013 2014 2015 2016 CAFOO 666 639 IS3 441 380 933 190 2S8 337 CAFOI S99 S73 088 377 380 111 S91 674 197 CAF02 363 ISI S16 636 044 2S8 413 413 CAF03 848 988 697 133 380 219 444 492 116 CAF04 664 638 IS1 439 369 379 126 204 373 CAF05 3S5 143 S07 627 378 369 380 296 291 CAF06 .883 022 728 232 379 18S 110 088 198 CAF07 S83 SIS 033 317 363 380 726 7S8 973 CAF08 748 721 23S S21 37S 749 OS8 149 3S8 CAF09 S83 SSS 071 3S8 380 811 80S 76S 072 CAFI0 664 638 IS2 440 379 7S2 OS9 lS0 380 CAFll 601 S7S 090 377 379 380 9l9 002 303 CAF12 366 IS3 S19 638 379 36S 718 624 727 CAF13 883 04S 7SS 961 3SS 366 IS6 811 909 CAF14 339 109 47S S9S 379 36S 7S2 662 764 CAF15 027 160 874 083 380 0SI 4S9 649 987 SASOI 373 338 8S7 133 344 928 178 247 211 SAS02 722 696 228 893 408 41S 3S2 416 022 SAS03 6S3 627 141 424 380 917 174 240 321 SAS04 6S1 626 139 42S 379 109 084 l91 380 SAS05-S8S SS8 073 3S9 380 378 308 377 92S SAS05-614 S89 102 389 302 379 941 038 339 SAS05-SS4 S26 042 018 380 938 208 302 379 SAS06 406 370 899 188 370 380 923 999 304 SAS07 680 6S4 167 l,4SS 369 377 003 079 340 SAS08 627 600 114 402 380 112 087 173 148 SAS09 601 S7S 090 377 379 917 171 241 2S0 SASI0 627 600 114 402 380 119 068 IS3 2S1 SASH 667 641 ISS 442 3S6 380 007 083 360 SAS12 614 S88 102 381 380 843 099 194 304 SAS13 S85 SS9 071 3S7 380 837 113 202 30S SAS14 630 604 118 1,404 380 843 099 19S 380 SAS15 38S 34S 869 ISI 380 380 897 980 274 SAS16 683 613 1,080 334 372 782 413 413 649 102 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table C.6 - Gas Additions, Including Combined Heat & Power Scenario. .. ... ' 200.7 200.8.'20.09 2010.2011.2012 2013.20.14 20.15 2016 CAFOO 12S 12S 12S 12S 12S CAFOI 140 742 134 S66 923 CAF02 100 100 100 100 100 CAF03 17S 17S 17S 17S 27S CAF04 CAFOS IS0 IS0 IS0 IS0 22S CAF06 734 7S9 7S9 7S9 7S9 CAFO7 CAF08 302 628 628 628 628 628 CAF09 CAFIO 327 211 211 211 211 211 CAFII 12S 12S 12S l2S 12S CAFI2 634 634 734 734 734 734 CAF13 12S 12S 12S 12S 12S CAFI4 12S 12S 12S 12S 12S CAFI:;12S 12S 12S 12S 12S SASOI 140 742 134 S66 923 SASO2 100 lOO 100 100 100 SASO3 17S l7S 17S 17S 27S SASO4 SASO:;-979 029 029 029 029 SASO:;-I:;236 236 236 236 236 SASO:;-302 7S9 361 361 361 361 SASO6 302 402 402 402 402 SASO7 634 684 684 684 684 SASO8 402 402 402 402 402 SASO9 427 427 427 427 427 SASIO 432 432 432 432 432 SAS II 634 6S9 6S9 6S9 6S9 SASI2 432 432 432 432 432 SASI3 402 402 402 402 402 SASI4 432 432 432 432 432 SASI:;407 4S7 4S7 4S7 4S7 SASI6 103 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table c.7 - IGCC Additions Scenario 2007 2008'2009 2010 2011.2012 2013 2014'2015 2016 CAFOO 200 CAFOI SOO SOO SOO CAF02 200 200 CAF03 697 20S 002 CAF04 CAFOS CAF06 CAF07 200 200 200 CAF08 CAF09 200 200 200 CAFIO CAFH CAF12 CAF13 S08 CAF14 CAF15 SOO SOO SOO SASOI 200 SAS02 SAS03 200 SAS04 SAS05- SAS05- SASOS- SAS06 SAS07 SAS08 SAS09 200 SASIO 200 SASH SAS12 7S0 7S0 7S0 9S0 SAS13 7S0 750 7S0 9S0 SAS14 7S0 7S0 7S0 7S0 SAS15 SAS16 104 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table c.S - Pulverized Coal Additions Scelhiil..iiT 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016. CAFOO 940 690 690 690 690 CAFOI 940 690 690 690 440 CAF02 600 3S0 690 690 690 CAF03 940 2,440 2,440 2,440 440 CAFO4 CAF05 CAF06 CAF07 940 940 690 690 690 CAF08 7S0 7S0 7S0 7S0 CAFO9 940 690 690 690 690 CAFI0 7S0 7S0 7S0 7S0 CAFll 340 340 090 090 090 CAF12 7S0 7S0 7S0 CAF13 600 940 690 440 2,440 CAF14 7S0 7S0 7S0 CAF15 940 690 440 2,440 440 SASOI 600 3S0 3S0 3S0 3S0 SAS02 600 600 940 940 690 SAS03 940 690 690 690 690 SAS04 940 690 690 690 690 SAS05-340 340 090 SAS05-7S0 7S0 7S0 SAS05- SAS06 600 600 3S0 3S0 3S0 SAS07 600 600 3S0 3S0 3S0 SAS08 600 3S0 3S0 3S0 690 SAS09 600 3S0 3S0 3S0 3S0 SASI0 600 3S0 3S0 3S0 3S0 SASll 600 600 3S0 3S0 3S0 SAS12 600 600 600 600 600 SAS13 600 600 600 600 600 SAS14 600 600 600 600 600 SAS15 340 340 090 090 090 SAS16 940 690 440 440 440 105 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table c.9 - Demand Side Management Additions (MW CapacitY) Scenario 2007 2008 2009.2010'.2011 1012. . J2013 2014'201S" 2016., CAFOO ISO ISO ISO ISO ISO CAFOI IS 1 IS1 IS1 IS1 ISI CAF02 CAF03 101 163 163 163 163 163 CAF04 CAFOS CAF06 169 169 169 CAF07 CAF08 129 129 129 129 129 CAFO9 CAFIO CAFII 211 211 211 211 CAFI2 14S ISO ISO ISO ISO CAFI3 CAFI4 ISO ISO ISO ISO ISO CAFI5 198 198 198 198 198 SASOI 161 161 161 161 161 SASO2 140 140 16l 161 SASO3 IS3 IS3 IS3 IS3 IS3 SASO-4 IS3 IS3 IS3 IS3 IS3 SASO5-150 209 209 209 209 SASO5- SASO5-IS4 IS4 IS4 IS4 244 SASO6 ISO ISO ISO ISO SASO7 124 124 124 124 SASOH 198 198 198 198 198 SASO9 ISO ISO ISO ISO ISO SASIO ISO ISO ISO ISO ISO SASII 14S 14S 14S 14S SASI2 137 137 137 137 137 SAS 13 IS3 IS3 IS3 IS3 IS3 SAS 1-4 IS3 IS3 IS3 IS3 201 SASI5 131 211 211 211 211 SASI6 106 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results. ... .. ..' ..... .......... ... ...... ADD ITI 0 N ALt~EMSENSITIVITYA.N AL Y S IS SCEN ARIOzRESIJL \fS This section reports the detailed CEM results for an additional set of sensitivity scenarios re- quested by participants at the August 2006 public input meeting. Specifically, participants re- quested that sensitivities to scenario variables be tested against different sets of "base" scenario assumptions. All but one of the scenarios in Table 7.1 were intended to examine the CEM's re- sponse to varying assumptions around the "medium" (CAFll) case. Participants requested stud- ies that varied the assumptions around the business-as-usual (CAFOO), the low cost bookend (CAFI4), and the high cost bookend (CAF16) scenarios. Table C.lD summarizes the additional sensitivity scenarios. Note that sensitivities were only se- lected if they involve a key scenario variable or planning assumption (such as the planning re- serve margin level), or are compatible with respect to how the alternative future scenario was defined. For example, the sensitivities for testing alternative CO2 adder values are not compatible with the business-as-usual case, since that case assumes no adder to begin with. Regarding the regional transmission project scenario, additional forward price forecasts would be required to support alternative market conditions, which PacifiCorp deemed as too burdensome given the other research priorities. A few other sensitivities were excluded because they are intended to fulfil) specific analytical requirements from the Oregon Public Utility Commission, such as SAS 15 ("plan to average of super-peak load" Table c.IO - Additional Sensitivity Scenarios for CEM Optimization Name Plan to 12% capacity reserve margin Plan to 18% capacity reserve margin CO2 adder implementation in 2016 Regional transmission project CO2 adder impact on resource selection: $10/ton (1990$) CO2 adder impact on resource selection: $15/ton (1990$) CO2 adder impact on resource selection: $20/ton (1990$) Low wind capital cost High wind capital cost Tables C.ll through c.15 compare PVRR and resource addition results for each of the additional sensitivity scenarios. The first table reports PVRR. The remaining five tables report nameplate ca- pacity accrued by 2016 for total resources, wind, gas, pulverized coal, and IGCC, respectively. 107 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table C.II- Present Value of Revenue Requirements Comparison ($ Billion) Plan to 12% capacity reserve margin Plan to 18% capacity reserve margin CO2 adder implementation in 2016 Regional transmission project CO2 adder impact on resource selection: $10/ton (1990$) CO2 adder impact on resource selection: $ 15/ton (1990$) CO2 adder impact on resource selection: $20/ton (1990$) Low wind capital cost High wind capital cost $19 424 $19 867 $19,803 $22 303 $24 589 $13 523 $13 703 Table C.I2 - Total Resources Accrued by 2016 (Megawatts) Plan to 12% capacity reserve margin Plan to 18% capacity reserve margin CO2 adder implementation in 2016 Regional transmission project CO2 adder impact on resource selection: $10/ton (1990$) CO2 adder impact on resource selection: $15/ton (1990$) CO2 adder impact on resource selection: $20/ton (1990$) Low wind capital cost High wind capital cost 535 584 775 735 722 790 1,789 Table C.B - Wind Resources Accrued by 2016 (Nameplate Megawatts) Name. Plan to 12% capacity reserve margin Plan to 18% capacity reserve margin CO2 adder implementation in 2016 Regional transmission project CO2 adder impact on resource selection: $lO/ton (1990$) CO2 adder impact on resource selection: $ 15/ton (1990$) CO2 adder impact on resource selection: $20/ton (1990$) Low wind capital cost High wind capital cost 300 200 400 400 600 500 400 $39 693 $44 773 $49,234 $47 018 $48 123 010 724 745 708 687 600 800 300 200 100 108 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table C.I4 - Gas Resources Accrued by 2016 (Megawatts) Name Plan to 12% capacity reserve margin Plan to 18% capacity reserve margin CO2 adder implementation in 2016 Regional transmission project CO2 adder impact on resource selection: $lO/ton (1990$) CO2adder impact on resource selection: $15/ton (1990$) CO2adder impact on resource selection: $20/ton (1990$) Low wind capital cost High wind capital cost 602 302 125 125 361 336 211 029 849 Table C.I5 - Pulverized Coal Resources Accrued by 2016 (Megawatts) Name Plan to 12% capacity reserve margin Plan to 18% capacity reserve margin CO2 adder implementation in 2016 Regional transmission project CO2 adder impact on resource selection: $lO/ton (1990$) CO2 adder impact on resource selection: $15/ton (1990$) CO2 adder impact on resource selection: $20/ton (1990$) Low wind capital cost High wind capital cost 690 690 750 750 440 440 440 2,440 440 350 350 Table C.I6 -IGCC Resources Accrued by 2016 (Megawatts) 200 Name Plan to 12% capacity reserve margin Plan to 18% capacity reserve margin CO2 adder implementation in 2016 Regional transmission project CO2 adder impact on resource selection: $l0/ton (1990$) CO2 adder impact on resource selection: $15/ton (1990$) CO2 adder impact on resource selection: $20/ton (1990$) Low wind capital cost High wind capital cost 200 1,494 997 500 500 500 109 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results For the detailed CEM results tables, fossil fuel resource additions are reported as nameplate mega- watts accrued as of the year listed. Wind resources are reported as the estimated megawatt peak ca- pacity contribution accrued as of the year listed. The annual figures are not additive. Contract quanti- ties were also grossed up by the planning reserve margin to reflect the assumption that contract pur- chases are firm. Table c.I7 - CEM Results: Aggregate Resource Additions i J . i :E ..i . ", ' i' , .'..'." " p:v:RRi' .(iliiilion~) 2007 BAU/ 12% PRM BAU/18% PRM BAU/Low Wind Cap Cost BAU/High Wind Cap Cost Low Cost Bookend! 12%PRM Low Cost Bookend! 18% PRM Low Cost Bookend/ $10 CO2 Low Cost Bookend/ $15 CO2 Low Cost Bookend/ $20 CO2 Low Cost Bookend! Low Wind Cap Cost Low Cost Bookend! High Wind Cap Cost High Cost Bookend/ 12%PRM High Cost Bookend/ 18% PRM High Cost Bookend/ $10 CO2 High Cost Bookend! $15 CO2 High Cost Bookend/ $20 CO2 $ 19 488 $ 19 933 $ 19,424 $ 19 867 $ 13 382 $ 13 672 $ 19 803 $ 22 303 $ 24 589 $ 13 523 $ 13 703 $ 48 825 $ 49 936 $ 39 693 $ 44 773 $ 49 234 ii i, , .' " 2008 2009 486 449 271 002 236 749 748 142 106 681 424 423 422 122 420 425 839 1,404 109 108 109 975 715 722 475 211 008 565 268 267 268 2010 978 1,496 237 236 209 209 207 209 724 308 001 999 001 ResotirceAdditio.llS", MnJ' , ." ,' " i "I , . , 2011 2012 2013 2014 263 2,431 2 880 2 972 3 046 O..... . . PVRR JMil1i?n$(. "'Uil 2016 MW)i 327 5. 789 528 523 296 831 576 575 572 572 575 233 837 511 510 511 881 693 683 416 413 943 950 688 680 673 653 659 652 691 670 694 669 528 185 174 855 1,404 938 672 641 638 662 660 911 158 4 506 828 808 237 456 3,443 231 1,489 025 759 724 722 722 711 399 283 907 204 4 653 838 4 259 4 917 543 243 302 406 927 674 640 638 634 632 738 521 137 143 172 831 535 584 507 028 775 735 722 790 789 338 068 010 724 745 5.2 11.2 12. 14. 9.1 110 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Low Cost Bookend!$ 47 018 368 130 298 031 528 863 211 661 152 708Low Wind Cap Cost Low Cost Bookend/$ 48 123 226 106 270 995 511 778 158 645 090 687High Wind Cap Cost Note: Business as Usual (BAU) Table C.I8 - CEM Results: Wind Resource Additions Nameplate MW) Scenario 2007 2008 2009 li.20'lO 2011 2012 2013 2014 2015 2016 BAU/200 200 200 200 200 200 200 200 200 20012% PRM BAU/200 300 300 300 300 300 300 300 300 30018% PRM BAU/100 300 300 300 300 300 300 300 300 300Low Wind Cap Cost BAU/200 200 200 200 200 200 200 200 200 200High Wind Cap Cost Low Cost Bookend/300 300 300 300 300 300 300 400 400 40012% PRM Low Cost Bookend!400 400 400 400 400 400 400 400 400 40018%PRM Low Cost Bookend!300 300 300 300 300 300 400 400 400 400$10 CO2 Low Cost Bookend!400 400 400 400 400 400 400 400 400 400$15 CO2 Low Cost Bookend!500 500 500 500 500 500 500 600 600 600$20 CO2 Low Cost Bookend!500 500 500 500 500 500 500 500 500 500Low Wind Cap Cost Low Cost Bookend!200 200 300 300 300 300 300 400 400 400High Wind Cap Cost High Cost Bookend/200 300 300 300 600 600 600 400 10012%PRM High Cost Bookend!300 300 300 300 300 400 400 400 600 2,40018% PRM High Cost Bookend!300 300 300 300 300 400 400 400 600 600$10 CO2 High Cost Bookend/300 300 300 300 300 400 400 400 600 800$15 CO2 High Cost Bookend!300 300 300 300 300 400 400 400 800 300$20 CO2 Low Cost Bookend!200 800 800 800 800 800 800 100 100 200Low Wind Cap Cost Low Cost Bookend!000 000 000 000 000 000 100 000 100 100High Wind Cap Cost III PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table C.I9 - CEM Results: Front Office Transactions Figures shown are megawatts acquired in each year, Contract quantities were grossed up by the planning reserve margin to reflect the assumption that coptract purchases are firm. Annual figures are not additive. Scenario . .".. .... . 2007 2008 2009 2010 2011 2012 2013 2014.2015 2016 BAU/12% PRM 440 404 933 218 380 079 171 244 326 BAU/18% PRM 719 692 213 505 380 934 205 291 380 BAU/499 465 987 278 380 111 380 180 272Low Wind Cap Cost BAU/703 676 190 1,478 096 267 894 965 247High Wind Cap Cost Low Cost Bookend!228 347 337 328 377 294 37012% PRM Low Cost Bookend!575 369 726 837 296 285 372 273 37418% PRM Low Cost Bookend!355 143 507 620 310 274 362 277 378$10 CO2 Low Cost Bookend!338 124 490 588 373 360 369 285 380$15 CO2 Low Cost Bookend!324 112 474 561 380 366 380 296 380$20 CO2 Low Cost Bookend!298 450 569 378 370 380 291 698Low Wind Cap Cost Low Cost Bookend!380 127 492 612 362 352 380 302 708High Wind Cap Cost High Cost Bookend!791 914 631 728 380 013 002 244 99512% PRM High Cost Bookend!303 136 879 294 363 210 488 690 97118% PRM High Cost Bookend!027 160 874 083 380 038 459 674 553$10 CO2 High Cost Bookend/036 195 908 111 377 022 972 697 749$15 CO2 High Cost Bookend!027 160 874 083 380 051 459 649 987$20 CO2 Low Cost Bookend!679 846 561 153 370 968 856 597 107Low Wind Cap Cost Low Cost Bookend!880 019 725 175 380 009 914 342 189High Wind Cap Cost 112 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table C.20 - CEM Results: Gas Additions, Including Combined Heat and Power (Nameplate MW) Scenario .' " 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 BAU/ 12% PRM BAU/125 125 125 125 12518% PRM BAU/ Low Wind Cap Cost BAU/ High Wind Cap 602 602 602 602 602 Cost Low Cost Bookend! 12% PRM Low Cost Bookend!548 548 548 548 54818%PRM Low Cost Bookend/302 302 302 302 302$10 CO2 Low Cost Bookend!125 125 125$15 CO2 Low Cost Bookend!125 125 125$20 CO2 Low Cost Bookend! Low Wind Cap Cost Low Cost Bookend! High Wind Cap Cost High Cost Book- end/417 849 849 849 849 849 12% PRM High Cost Book- end!327 327 327 631 631 631 631 631 18%PRM High Cost Book- end!327 361 361 361 361 361 $10 CO2 High Cost Book- end!302 336 336 336 336 336 $15 CO2 High Cost Book- end!327 211 211 211 211 211 $20 CO2 Low Cost Bookend! Low Wind Cap 904 004 004 004 004 029 Cost Low Cost Bookend! High Wind Cap 849 849 849 849 849 Cost 113 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table C.2I - CEM Results: IGCC Additions (Nameplate MW) ..... ScenarIo 2007 2008 2009 2010 2011 2013 2014 '2015 2016 BAD/ 12% PRM 200 BAD/ 18% PRM 200 BAD/Low Wind 200Cap Cost BAD/High Wind Cap Cost Low Cost Bookend! 12% PRM Low Cost Bookend! 18% PRM Low Cost Bookend! $10 CO2 Low Cost Bookend! $15 CO2 Low Cost Bookend! $20 CO2 Low Cost Bookend! Low Wind Cap Cost Low Cost Bookend! High Wind Cap Cost High Cost Book- end/500 500 500 12%PRM High Cost Book- end!500 500 500 18%PRM High Cost Book- end!500 500 494 $10 CO2 High Cost Book- end!500 500 997 $15 CO2 High Cost Book- end!500 500 500 $20 CO2 Low Cost Bookend/ Low Wind Cap 500 500 500 Cost Low Cost Bookend/ High Wind Cap 500 500 500 Cost 114 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table C.22 - CEM Results: Pulverized Coal Additions MW)amepJ ate . . 2007,.2011 2014'Scenario 2008 2009 2010 2012 2013 2015;'2016. BAU/940 690 690 690 69012% PRM BAU/940 690 690 690 69018% PRM BAU/ Low Wind Cap 940 690 690 690 690 Cost BAUI High Wind Cap 940 940 690 690 690 Cost Low Cost Bookend/ )~"-;) PRM Low Cost Bookend/ IX";. PRM Low Cost Bookend! S I 0 CO~ Lo\\ ('ost Bookend/ S I :' CO~ Lm\ Cost Bookend! S~O CO~ Low Cost Bookend! Lo\\ Wind Cap 750 ost Lo\\ ('ost Bookend! lIigh Wind Cap 750 ost lIigh Cost Book- end 940 690 690 690 440 I~"" PRM lIigh Cost Book- end 940 440 440 440 440 IX"" PRM lIigh Cost Book- end 940 690 2,440 440 440 SIOCO, lIigh Cosl Book- end 940 690 690 2,440 440 S I ~ CO, lIigh Cost Book- end 940 690 440 440 440 S~O ('()~ Low Cost Bookend! LO\\ Wind Cap 940 690 690 2,440 440 Cost Low Cost Bookend! High Wind Cap 940 690 690 690 440 Cost 115 PacifiCorp 2007 IRP Appendix C - Detailed CEM Modeling Results Table c.23 - CEM Results: Demand-side Management Additions (MW Capacity) 2015. Scenario. ..... . 2007 2008.2009 2010'2011 ... 2012 2013 2014 2016 BAU/ 12% PRM BAU/153 153 153 153 15318% PRM BAU/ Low Wind Cap Cost BAU/ High Wind Cap Cost Low Cost Bookend! 12% PRM Low Cost Bookend! 18% PRM Low Cost Bookend! $10 CO2 Low Cost Bookend!145 145 145 145 145 $15 CO2 Low Cost Bookend! $20 CO2 Low Cost Bookend!145 145 145 145 145Low Wind Cap Cost Low Cost Bookend!150 150 150 150 150High Wind Cap Cost High Cost Bookend!198 198 198 198 19812% PRM High Cost Bookend/133 140 140 140 140 14018% PRM High Cost Bookend! $10 CO2 High Cost Bookend! $15 CO2 High Cost Bookend!198 198 198 198 198 $20 CO2 Low Cost Bookend/ Low Wind Cap Cost Low Cost Bookend!195 195 195 195 195High Wind Cap Cost 116 PacifiCorp 2007 IRP Appendix D Supplementary Portfolio Information APPENDIX D - SUPPLEMENTARY PORTFOLIO INFORMATION This appendix reports additional information for the risk analysis portfolios discussed in Chapter 7. This information consists of carbon dioxide emissions quantity and cost data, as well as a component cost breakdown of the stochastic mean Present Value of Revenue Requirements (PVRR) reported for the risk analysis portfolios. CARBO NDI OXIDEEMISSI ONS Table D.l shows cumulative CO2 emissions for 2007 through 2026 attributable to retail sales only, allocated to each state. Table D.2 reports unit emission costs (cents/MWh) by new fossil fuel resource for the risk analy- sis portfolios considered as finalists for preferred portfolio selection (Group 2 portfolios). The results are reported for 2016 based on the $8/ton CO2 adder case. Table D.I - CO2 Emissions Attributable to Retail Sales by State I proup 0 lOS I .. ' ". .. .. .. .. .. .. .. . i' I . .. .. .. . CO2 Emissions.attributableto Retail Sales,2007~2026 (lOOOTons) tJtab .1dabo m ' .. . ill SvstemTotal California . Ore20n . Washin2ton Wvominl!. RAI 120 694 17,481 262 468 363 500,054 432 189 897 RA2 111 948 342 260 377 678 496 227 910 188 413 RA3 115 336 388 261 003 889 498 000 073 188 984 RA4 121 824 494 262 636 420 500 715 65,475 190 084 RA5 115 003 388 261 047 899 497 671 077 188 920 RA6 104 309 228 258 687 122 492 675 64,484 187 112 RA7 089,439 997 255 229 988 486 009 619 184 596 RA8 128 175 594 264 156 917 503 490 854 191 163 RA9 1,123 075 517 263 001 538 501 159 564 190 296 RAlO 119 534 17,462 262 184 270 499 558 360 189 699 RAIl 109,867 308 259 850 508 495 373 779 188 049 RA12 110 384 320 260,043 566 495 486 824 188 146 2P U roup 0 lOS ;. . ., . CO2 Emissionsattriblltable to Retail Sales 2007-2026 (1000 Tons) . , $8 Adder California.Ore20n .Washiri2ton Utah 'Idaho Wvomin2 RA13 127 571 586 264 045 886 503 165 828 191 061 RA14 064 710 624 249 713 179 474 567 234 180 393 RA15 068 540 683 250 584 81,465 476 315 453 181 041 RA16 057 885 517 248 100 652 471 557 832 179 227 RA17 075,848 796 252 296 027 479 570 881 182 278 117 PacifiCorp 2007 IRP Appendix Supplementary Portfolio Information Table D.2 - Unit Emission Costs for Group 2 Risk Analysis Portfolio Resources, 2016 " c. , , c " " "" .,, , ..c " ':" S()2 NOx l lJg CQ2i . , " '" ", . '.c. i " i i' "Cost Cost -Cost 'Cost Portfolio Location anilFossilFueIResources . ' J ' ' ," .' : CeJltslMWh " . ,. '' " PortfolioRA"13 , ; "' . .,. ', ,, .".""'.' ''. " ".c" . "".' East Utah supercritical pulverized coal Wyoming supercritical pulverized coal Utah supercritical pulverized coal 2 (added in 2017) Wyoming supercritical pulverized coal 2 (added in 2018) Combined Heat and Power WestCombined Heat and Power 395 0.1 13.1 1.4 287. P';rtrolioRA14."c.,ii "..ii " .:." 'i " '.,. ".:"' i . East Utah supercritical pulverized coal Wvoming supercritical pulverized coal Combined Cycle Combustion Turbine, F Class, 2xl wi duct firing Combined Cvcle Combustion Turbine, G Class lxl wi duct firing Combined Heat and Power West Combined Cycle Combustion Turbine, F Class, 2xl wi duct firing Combined Heat and Power Portfolio RAlS East Utah supercritical pulverized coal Wyoming supercritical pulverized coal Combined Cycle Combustion Turbine, F Class, 2xl wi duct firing Combined Heat & Power West Combined Cycle Combustion Turbine, F Class, 2xl wi duct firing Combined Heat and Power PortfolioRAlb ' ", ..' '' , , ", ", "" "" . .c,." " , East Utah supercritical pulverized coal Wyoming supercritical pulverized coal Combined Cycle Combustion Turbine, F Class 2xl wi duct firing Combined Cycle Combustion Turbine, F Class, 2xl wi duct firing Combined Heat and Power West Combined Cycle Combustion Turbine, F Class 2xl wi duct fITing Combined Heat and Power PortfolioRA17 c",. cc." . '..', '.:.. East Utah supercritical pulverized coal Wyoming supercritical pulverized coal Combined Heat & Power West Combined Cycle Combustion Turbine, F Class 2xl wi duct firing Combined Heat and Power , ". '' , .'C.' 642 011 140 584 864 283 571 143 15. 16. 15. 16. 38. 39.1 13. 38. 39.1 13. 880. 898. 1.4 286.4 1.4 880. 898. 411.5 405. 286.4 086 0.1 4.8 2.0 416.402 0.1 13.1.4 287.i , " ".""' ". ." "' '', , ,, . 607 926 382 142 956 392 .. .." ,. ,, " 544 821 320 320 143 058 401 651 044 141 836 382 15. 16. 0.1 ... " 15. 16. 38. 39.1 13.1.4 880. 898. 411.5 286.4 8 2.0 416. 13.1.4 287. . ' " C' ' "' , 38. 39. 13. 1 4. 0.1 13. 15. 16. 38. 39. 13. 13. 1.4 880. 898. 411.5 411.5 286.4 1.4 416. 287. 1.4 880. 898. 286.4 1.4 416. 287. 118 PacifiCorp 2007 IRP Appendix D Supplementary Portfolio Information Figures D.l and D.2 show the CO2 intensity (as measured by CO2 tons produced per megawatt- hours generated) for the Group 2 portfolios in the $8/ton and $61/ton CO2 adder cases from 2007 through 2016. Figure D.I - Annual CO2 Intensity, 2007-2016 ($8 CO2 Adder Case) (From generation plus amount assigned to net wholesale market purchases) 000 950 900 _..... s:: ::;; ~ 0.850 800 750 700 2007 2008 009 2010 2011 2012 2013 014 I--RA13 """"-RA14 "'X-RA15 ~RA16 -+-RA17 I 2015 2016 119 PacifiCorp 2007 IRP Appendix D Supplementary Portfolio Information Figure D.2 - Annual CO2 Intensity, 2007-2016 ($61 CO2 Adder Case) (From generation plus amount assigned to net wholesale market purchases) 000 950 750 900 ::;: \!1 0.850 800 700 2007 2008 009 2010 2011 2012 2013 2014 I----RA13 -'-RA14 -~-"RA15 -*-RA16 ~RA17 2015 2016 120 Pa c i f i C o r p 20 0 7 I R P Ap p e n d i x D Su p p l e m e n t G l Y P o r t f o l i o In f o r m a t i o n PO R T F O L I O P V R R C O S T C O M P O ~ E ~ T C O M P A R I S O N Ta b l e s D . 3 t h r o u g h D . 5 s h o w s t h e b r e a k d o w n o f e a c h p o r t f o l i o s s t o c h a s t i c m c a n P V R R b y v a r i a b l c a n d f i x e d c o s t co m p o n e n t s . T h e s e co s t s r e f l e c t t h e S ~ / t o n CO ~ c o s t a d d e r s c e n a r i o . T a b l e D . 3 r e p o r t s G r o u p 1 r i s k a n a l y s i s p o r t f o l i o s a s s u m i n g a c a p - a n d - tr a d e c o m p l i a n c e st r a t e g y a s d e s c r i b e d i n t h e E n v i r o n m e n t a l E x t e r n a l i t y C o s t s e c t i o n o f C h a p t e r 6 . T a b l e s D . 4 a n d D . 5 r e p o r t t h e c o s t c o m p o n e n t b r e a k - do w n f o r G r o u p 2 r i s k a n a l y s i s p o r t f o l i o s f o r b o t h t h e CO 2 c a p - a n d - tr a d e a n d t a x c o m p l i a n c e s t r a t e g i e s . Ta b l e D . 3 - G r o u p I : P o r t f o l i o P V R R Co s t C o m p o n e n t s ( C a p - a n d - Tr a d e S t r a t e g y ) Co s t C o m p o o t ) o t . ($ O O O ) RA I RA 2 RA 3 . RA 4 RA 5 RA 6 Va r i a b l e C o s t To t a l F u e l C o s t 96 5 98 9 21 9 , 65 7 74 7 20 3 07 1 61 8 86 3 81 9 11 , 4 6 6 51 9 Va r i a b l e O & M C o s t 66 6 01 6 68 8 , 4 5 6 65 3 82 5 68 5 17 0 66 4 32 3 60 9 74 8 To t a l E m i s s i o n C o s t (4 9 1 45 6 ) (5 2 4 67 0 ) (5 8 3 58 1 ) (4 9 4 61 7 ) (5 4 1 90 9 ) (6 3 3 38 4 ) Lo n g T e r m Co n t r a c t s a n d 06 3 90 2 98 9 76 9 99 3 , 4 4 1 78 4 53 9 99 0 02 0 94 2 40 3 Fr o n t O f f i c e T r a n s a c t i o n s Sp o t ' Ma r k e t B a l a o c i o e Sa l e s 17 1 40 5 ) 70 1 18 0 ) 02 8 21 2 ) 48 4 12 0 ) 65 4 68 2 ) 79 0 39 5 ) Pu r c h a s e s 09 7 60 5 25 6 92 2 4, 1 5 6 08 3 50 6 04 3 06 4 02 3 52 6 76 4 En e r g v N o t S e r v e d 62 9 17 5 50 6 35 8 57 8 21 8 59 9 32 5 40 7 71 3 64 9 40 2 To t a l V a r i a b l e 13 , 75 9 , 82 5 13 , 43 5 , 31 3 13 , 51 6 , 97 8 13 , 66 7 95 8 12 , 79 3 , 30 6 77 1 , 05 6 Ne t P o w e r C o s t s Re a l L e v e l i z e d F i x e d C o s t s 58 5 , 99 4 07 8 72 5 99 8 , 11 9 82 1 , 19 4 44 4 , 52 8 54 1 , 45 7 To t a l P V R R 34 5 , 82 0 51 4 03 8 51 5 , 09 7 21 , 48 9 , 15 2 22 , 23 7 , 83 4 31 2 51 3 12 1 Pa c i f i C o r p 20 0 7 I R P Ap p e n d i x D Su p p l e m e n t a r y P o r t f o l i o I n f o r m a t i o n Va r i a b l e C o s t To t a l F u e l C o s t Va r i a b l e O & M C o s t To t a l E m i s s i o n C o s t Lo n g T e r m Co n t r a c t s a n d Fr o n t O f f i c e T r a n s a c t i o n s S o t M a r k e t B a l a n c i n Sa l e s Pu r c h a s e s En e r No t S e r v e d To t a l V a r i a b l e Ne t P o w e r C o s t s Re a l L e v e l i z e d F i x e d C o s t s To t a l P V R R 75 5 43 4 13 8 73 1 49 6 35 5 12 , 92 5 14 2 27 2 , 52 6 71 7 10 3 19 9 , 09 6 64 2 , 24 5 47 1 62 2 84 0 77 3 46 7 , 4 4 1 82 3 26 7 14 , 02 7 , 89 5 93 5 , 84 7 96 3 74 2 06 4 97 8 ) 14 0 30 6 69 8 51 0 13 , 69 9 , 60 5 18 2 , 47 8 88 2 08 3 (7 , 01 3 12 5 16 7 82 0 58 3 16 5 13 , 17 9 , 44 7 58 9 , 96 8 21 , 76 9 , 41 5 75 1 04 5 45 6 95 1 69 5 59 9 13 , 60 0 , 44 9 15 3 , 39 5 21 , 75 3 , 84 4 12 2 Pa c i f i C o r p 20 0 7 I R P Ap p e n d i x D Su p p l e m e n t a r y P o r t f o l i o I n f o r m a t i o n Ta b l e D . 4 - G r o u p 2 : P o r t f o l i o P V R R C o s t C o m p o n e n t s (C O 2 C a p - a n d - T r a d e Co m p l i a n c e S t r a t e g y ) Co s t C o m o n e n t $0 0 0 Va r i a b l e C o s t To t a l F u e l C o s t Va r i a b l e O & M C o s t To t a l E m i s s i o n C o s t Lo n g T e r m Co n t r a c t s a n d F r o n t Of f i c e T r a n s a c t i o n s 46 3 92 4 38 1 07 3 49 8 01 5 40 0 55 6 95 9 80 1 S o t M a r k e t B a l a n c i n Sa l e s 97 0 50 3 ) 13 9 52 6 ) 12 9 54 6 ) 31 1 10 8 ) 15 6 92 6 ) Pu r c h a s e s 01 1 22 1 78 1 17 6 80 5 00 9 62 6 55 4 85 8 92 5 En e r No t S e r v e d 94 2 29 0 54 6 11 9 61 4 73 6 50 4 48 9 67 0 81 4 To t a l V a r i a b l e 15 , 50 3 , 55 9 14 , 31 1 , 85 9 48 6 , 39 0 10 1 , 28 9 84 3 , 76 9 Ne t P o w e r C o s t s Re a l L e v e l i z e d F i x e d C o s t s 50 6 , 39 4 24 7 , 00 5 14 5 , 76 0 52 3 , 53 7 90 6 , 26 1 To t a l P V R R 00 9 , 95 3 21 , 55 8 , 86 4 21 , 63 2 , 15 0 62 4 82 6 75 0 , 03 0 12 3 Pa c i f i C o r p 20 0 7 I R P Ap p e n d i x D Su p p l e m e n t a r y P o r t f o l i o I n f o r m a t i o n Ta b l e D . 5 - G r o u p 2 : P o r t f o l i o P V R R C o s t Co m p o n e n t s ( C O 2 T a x C o m p l i a n c e S t r a t e g y ) Co s t C o m p o n e n t ( 5 0 0 0 ) RA 1 3 RA 1 4 RA 1 5 RA 1 6 RA I 7 Va r i a b l e C o s t To t a l F u e l C o s t 87 9 72 4 74 0 , 4 7 5 68 7 08 8 89 3 18 7 49 6 32 2 Va r i a b l e O & M C o s t 67 7 64 4 68 8 63 9 68 6 25 3 69 5 13 2 67 5 58 5 To t a l E m i s s i o n C o s t 41 9 59 6 23 2 88 3 24 3 85 2 21 1 34 2 25 8 30 7 Lo n g T e r m C o n t r a c t s a n d F r o n t 46 3 92 4 38 1 07 3 49 8 01 5 40 0 55 6 95 9 80 1 Of f i c e T r a n s a c t i o n s Sp o t M a r k e t B a l a n c i n 2 Sa l e s (7 , 97 0 50 3 ) 13 9 52 6 ) 12 9 54 6 ) 31 1 10 8 ) 15 6 92 6 ) Pu r c h a s e s 01 1 22 1 78 1 17 6 80 5 00 9 62 6 55 4 85 8 92 5 En e r g v N o t S e r v e d 94 2 29 0 54 6 11 9 61 4 73 6 50 4 48 9 67 0 81 4 To t a l V a r i a b l e 42 3 , 89 5 19 , 23 0 , 83 8 19 , 40 5 , 40 7 02 0 , 15 3 19 , 76 2 82 7 Ne t P o w e r C o s t s Re a l L e v e l i z e d F i x e d C o s t s 50 6 , 39 4 24 7 , 00 5 14 5 , 76 0 52 3 , 53 7 90 6 26 1 To t a l P V R R 26 , 93 0 28 9 26 , 47 7 , 84 3 55 1 , 16 6 54 3 , 69 1 66 9 , 08 9 12 4 PacifiCorp 2007 IRP Appendix E Stochastic Risk Analysis Methodology APPENDIX E - STOCHASTIC RISK ANALYSIS METHODOLOGY OVERVIEW PacifiCorp analyzes potential portfolios over possible future conditions to assess the perform- ance of each portfolio under uncertainty. Global Energy s Planning and Risk (PaR) model is used to perform a stochastic assessment of portfolios in which system loads, hydroelectric energy availability, thermal unit outages, and wholesale electric and gas prices are varied to reflect un- certainty. Stochastic representations of these variables include specific volatility and correlations parameters. In the case of four of the five uncertainties described previously (PaR treats thermal outages separately), there are potentially short-term and long-term stochastic parameters (volatil- ities and correlations). The following is a discussion of the stochastic model specification, the short-term and long-term parameters and results of the stochastic simulation studies. STOCHASTIC VARIABLES PacifiCorp s analysis is performed for the following stochastic variables: Fuel prices (natural gas prices for the company s western and eastern control areas), Electricity market prices for Mid-Columbia (Mid C), California - Oregon Border (COB), Four Corners, and Palo Verde (PV), Electric transmission area loads (California, Idaho, Oregon, Utah, Washington and Wyoming regions) and Hydroelectric generation The PaR's stochastic tool determines a set of stochastic model parameters based on data entered by the user. During model execution, PaR makes time path dependent Monte Carlo draws for each stochastic variable based on the input parameters. The Monte Carlo draws are of percent- age deviations from the expected forward value of the variables. In the case of natural gas prices, electricity prices and regional loads, PaR applies Monte Carlo draws on a daily basis. In the case of hydroelectric generation, Monte Carlo draws are applied on a weekly basis. The PaR Stochastic Model PaR's stochastic model is a two factor (a short-run and a long-run factor) short-run mean revert- ing model. Variable processes assume normality or log-normality as appropriate. Separate vola- tility and correlation parameters are used for modeling the short-run and long-run factors. The short-run process defines seasonal effects on forward variables, while the long-run factor defines random structural effects on electricity and natural gas markets and retail load regions. The short-run process is designed to capture the seasonal patterns inherent in electricity and natural gas markets and seasonal pressures on electricity demand. Mean reversion represents the speed at which a disturbed variable will return to its seasonal expectation. With respect to market prices, the long-run factor should be understood as an expected equilibrium, with the Monte Carlo draws defining a possible forward equilibrium state. In the case of regional electricity loads, the Monte Carlo draws define possible forward paths for electricity demand. The short-run seasonal stochastic parameters are developed using a single period auto-regressive regression equation (commonly called an AR(1) process). The standard error of the seasonal 125 PacifiCorp 2007 IRP Appendix E Stochastic Risk Analysis Methodology regression defines the short run volatility, while the regression coefficient for the AR(I) variable defines the mean reversion parameter. The short-run regression errors are correlated seasonally to capture inter-variable effects from informational exchanges between markets, inter-regional impacts from shocks to electricity demand and deviations from expected hydroelectric genera- tion performance. . The long-run parameters are derived from a random-walk with drift regression. The standard error of the random-walk regression defines the long-run volatility for the regional electricity load variables. In the case of the natural gas and electricity market prices, the standard error of the random walk regression is interpolated with the volatilities from the company s Official Forward Price curve for March 31 , 2006 over the twenty year study period. The long-run regres- sion errors are correlated to capture inter-variable effects from changes to expected market equi- librium for natural gas and electricity markets as wen as the impacts from changes in expected regional electricity loads. For a detailed specification of the PaR stochastic model, please refer to the 2004 IRP Appendix STOCHASTIC OUTPUT Presented below are graphical stylized outputs from the 100 stochastic iterations made by the Planning and Risk model. Eastern and western natural gas and electricity market prices (Figures l through E.8) are presented showing the frequency of prices for 2007 and 2016. In the case of stochastic regional electricity loads (Figures E.9 through E.13), the 90th, 75 , 25th and 10th percentiles as wen as the mean are presented. For hydroelectric generation (Figures E.14 and 15), the 75th, 50th, 25th percentiles are presented. Figure E.I- 2007 Frequency of Eastern (Palo Verde) Electricity Market Prices -100 Iterations f! 40 '0 30 131 175 2'9 263 $1 MWh 307 351 394 438 126 PacifiCorp 2007 IRP Appendix E Stochastic Risk Analysis Methodology Figure E.2 - 2016 Frequency of Eastern (Palo Verde) Electricity Market Prices -100 Iterations :;:;:!::...;:.. I,) ::I u.. 131 175 213 263 $1 MWh 307 351 394 438 Figure E.3 - 2007 Frequency of Western (Mid C) Electricity Market Prices -100 Iterations ~ 50 : 0 i ~ I ell ~ =: . '0 : ~ i 20 ::I : C' , ~ u.. 0 D t14 285142 171 MWh 139 228 256 Fi~ure E.4 - 2016 Frequency of Western (Mid C) Electricity Market Prices -100 Iterations ell :!::...;:.. I,), I:, ellI ::I i C' u.. t14 142 171 139 228 256 285 $1 MWh 127 PacifiCorp 2007 IRP Appendix E Stochastic Risk Analysis Methodology . Figure E.5 - 2007 Frequency of Eastern Natural Gas Market Prices -100 Iterations I : '0 30 ::-. 5i 20:::s W 10II- 24 30 $1 MMBtu Figure E.6 - 2016 Frequency of Eastern Natural Gas Market Prices - 100 Iterations ~ 50 I!! 40 CII '0 30 5i 20:::s f!! 10 II- 24 30 $1 MMBtu Figure E.7 - 2007 Frequency of Western Natural Gas Market Prices -100 Iterations ~ 50 I!! 40 CII '0 30 ::-. 5i 20:::s f!! 10II- $1 MMBtu 128 PacifiCorp 2007 IRP Appendix E Stochastic Risk Analysis Methodology Figure E.8 - 2016 Frequency of Western Natural Gas Market Prices -100 Iterations :g 50 :;:; ~ 40 '0 30 ;:.., ~ 20 W 10 u.. 25 $/ MMBtu Figure E.9 - Goshen Loads 000 5,000 000 000 ..c: s: 4,000 000 000 000 -90th ~75th mean =',;r='25th -10th 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 129 PacifiCorp 2007 IRP Appendix E Stochastic Risk Analysis Methodology 70,000 Figure E.IO - Utah Loads 60,000 000 40,000 30.000 . 20,000 . 10.000 ... -90th ~75th mean -0"'"'25th -10th 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Figure E.II - Washington Loads 10.000 000 000 000 000 ~ 5.000 r... 000 000 000 000 .-90th~75th mean~.25th-1Oth 0 . 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 130 PacifiCorp 2007 IRP Appendix E Stochastic Risk Analysis Methodology Figure E.I2 - West Main (California and Oregon) Loads 30,000 000 25,000 ..c ~ 15,000 ...... 10,000 000 -90th ~75th mean ""TcTNHo'25th -10th 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Figure E.13 - Wyoming Loads 14,000 10,000 000 --- 000 000 000 -90th ~75th mean -b.-25th -10th 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 131 PacifiCorp 2007 IRP Appendix E Stochastic Risk Analysis Methodology Figure E.I4 - 2007 Hydroelectric Generation Percentile 000 000 000 000 .c: 3: 4 000 000 000 000 747 75th 50th 25th Figure E.IS - 2016 Hydroelectric Generation Percentile 000 000 699 000 000 .c: 3: 4 000 000 000 000 75th 115 051 50th 25th 132 PacifiCorp 2007 IRP Appendix F Public Input Process APPENDIX F - PUBLIC INPUT PROCESS A critical element of this resource plan is the public input process. PacifiCorp has pursued an open and collaborative approach involving the Commissions, customers and other stakeholders in PacifiCorp s planning process prior to making resource planning decisions. Since these deci- sions can have significant economic and environmental consequences, conducting the resource plan with transparency and full participation from Commissions and other interested and affected parties is essential. The public has been involved in this resource plan from its earliest stages and at each decisive step. Participants have both shared comments and ideas and received information. As reflected in the report, many of the comments provided by the participants have been adopted by Pacifi- Corp and have contributed to the quality of this resource plan. PacifiCorp will adopt further comments going forward, either as elements of the Action Plan or as future refinements to the planning methodology. The cornerstone of the public input process has been full-day public input meetings held ap- proximately every six weeks throughout the year-long plan development period. These meetings have been held jointly in three locations, Salt Lake City, Portland and Cheyenne (Starting from the April 20 2006), using telephone and video conferencing technology, to encourage wide par- ticipation while minimizing travel burdens and respecting everyone s busy schedules. The 2007 public input meetings were augmented by a series of focused technical workshops to provide an opportunity to discuss complex topics for a multi-state utility in more detail. PARTICIPANT LIST Among the organizations that were represented and actively involved in this collaborative effort were: Commissions Idaho Public Utilities Commission Oregon Public Utilities Commission Public Service Commission of Utah Washington Utilities and Transportation Commission Wyoming Public Service Commission Intcncnors Citizen s Utility Board of Oregon Committee for Consumer Services State of Utah Energy Trust of Oregon Energy Strategies, LLC Industrial Customers of Northwest Utilities Mountain West Consulting, LLC 133 PacifiCorp 2007 IRP Appendix F Public Input Process Northwest Energy Efficiency AHiance Northwest Power and Conservation Council . NW Energy Coalition Oregon Department of Energy Renewables Northwest Project Salt Lake City Salt Lake Community Action Program Southwest Energy Efficiency Project Sierra Club , Utah Chapter Utah Association of Energy Users Utah Clean Energy Alliance Utah Division of Air Quality Utah Division of Public Utilities Utah Energy Office Utah Geological Survey Utah Governor Office Utah Legislative Watch Wasatch Clean Air Coalition Western Resource Advocates West Wind Wires Wyoming Industrial Energy Consumers Wyoming Office Of Consumer Advocacy Others Portland General Electric (PGE) Puget Sound Energy (PSE) A vista Utilities Quantec LLC John Klingele Global Energy Decisions, LLC PacifiCorp extends its gratitude for the time and energy these participants have given to the re- source plan. Your participation has contributed significantly to the quality of this plan, and your continued participation wiH help as PacifiCorp strives to improve its planning efforts going for- ward. PUBLIC INPUT MEETINGS PacifiCorp hosted eight full-day public input meetings, three technical workshops and three general meetings between the 2004 and 2007 IRP process which discussed various issues includ- ing inputs and assumptions, risks, modeling techniques, and analytical results. Below are the agendas from the public input meetings and the technical workshops. 134 PacifiCorp 2007 IRP Appendix F Public Input Process 2005 Public Process May 18, 2005 - General Meeting Results of IRP Stakeholder Satisfaction Survey Overview of PacifiCorp Transmission Procurement Update Implementation of Supply Side Actions in 2004 IRP Action Plan Renewables RFP RFP 2009 Front Office Transactions . DSM Update DSM in the 2004 IRP Class 1 and Class 2 Update DSM Procurement Update on Inputs and Assumptions Update on Models PaR Conversion Capacity Expansion Module August 3, 2005 - General Meeting Load Forecasting Annual Review National Economic Outlook Regional Economic Review Tools and Inputs of the Residential Forecast Preliminary Residential Sales Forecast IRP Benchmarking Study Scope and Overview Findings IRP Action Plan Update RFP 2003 B Renewable RFP 2009 RFP 2011 Transmission (Regional Initiatives) DSM Update CEM Model Update 2004 IRP Update Plan Outline Schedule October 5, 2005 - General Meeting Update on IRP Acknowledgement Load and Resource Balance Update . New Portfolio Development / Overview of Analysis Status of Update Filing Progress on IRP Action Plan RFP 2003 B Renewable, RFP 2009 135 PacifiCorp 2007 IRP Appendix F Public Input Process DSM Update Load Forecasting Technical Workshop - Annual Review Comparisons of State Economic Forecasts Commercial Electric Model Design and Inputs Preliminary Commercial Economic and Sales Forecast 2006 Public Process December 7, 2005 - General Meeting Overview of 2006 IRP Public Process IRP Team Update 2006 IRP Work Plan PIM Participant Working Group ("WG") Approach Public Process Expectations 2006 IRP Studies 2004 IRP Update Summary and Revised Action Plan January 13,2006 - Renewables Workshop Review and discuss Wind Resource Analysis Plan Discuss Capacity Expansion Module (CEM) renewable supply curve modeling approach Summary . Comments, Questions, and Suggestions . Z-Statistic Method for Estimating Resource Peak Load Carrying Capability January 24, 2006 - Load Forecasting Workshop Preliminary Industrial Energy Sales Forecast State by State Mix and Growth by Sector - 2007 and 2017 Sector by Sector Model Review Hourly Load Forecast General Model Specification by Jurisdiction Forecast Process Improvements in the Process System Coincident Peak Demand & Jurisdiction Contribution Results State Peak Demands Next Steps Price Elasticity Price Elasticity in Current Models Econometric Elasticity Calculations Price Reaction of Customers Who Caned About the Rate Change Elasticity Among Customer Sub-Groups Potential Further Research 136 PacifiCorp 2007 IRP Appendix F Public Input Process February 10, 2006 - Demand-Side Management Workshop 2004 IRP DSM modeling Review Modeling Plan for 2006 IRP Planning Drivers and Objectives Modeling Approach Overview Program Assumptions for 2006 IRP 2005 DSM RFP Summary and Challenges Summation and Next Steps April 20, 2006 - General Meeting Update on IRP Inputs, Assumptions, and Studies Climate Change Policy Developments . CO2 Analysis in the 2006 IRP Integrated Gasification Combined Cycle (IGCC) Analysis Update Treatment of IGCC in the 2006 IRP . Long-Term Load Forecast Preliminary Load & Resource Balance May 10,2006 - General Meeting Natural Gas and Electricity Forecasts Renewables Studies Procurement Update June 7, 2006 - General Meeting . Demand-Side Management: Class I & III Resource Assessment Update Procurement Update: Demand-Side Management Procurement Update: Supply-Side Resources IRP Resource Alternatives IRP Transmission Analysis Approach Portfolio Analysis Scenarios and Risk Analysis Resource Adequacy/Capacity Planning Margin August 23, 2006 - General Meeting Introduction: Capacity Expansion Module (CEM) Analysis Scenario Review General Observations Total Portfolio Costs Generation, Demand-Side Management (DSM), and Market Purchases Transmission Sensitivity Studies . CO2 Adder Impacts Summary Results Modeling Conclusions and Candidate Portfolio Development Process Appendix: Modeling Results - Annual Resource Additions by Scenario 137 PacifiCorp 2007 IRP Appendix F Public Input Process October 31 , 2006 - General Meeting Candidate Portfolio Development Detailed Simulation Results and Conclusions Stochastic Cost/Risk Trade-off Analysis Results Reliability Analysis Results CO2 emissions for $8/ton CO2 adder case Quantec DSM Proxy Supply Curve Study Feedback on Capacity Expansion Module Results IRP Document Overview 2007 Public Process February 2007 - General Meeting Status of the Integrated Resource Plan Status of the 2012 Request for Proposal Conclusions resulting from stakeholder feedback Proposed path forward Impact on the current Integrated Resource Plan Discussion and Comments April 18, 2007 - General Meeting Load Forecast Update Summary of Changes to Forecast Changes in Economic Conditions Major Sales Changes by Jurisdiction Load and Resource Balance Update Preferred Portfolio Action Plan Portfolio Modeling Update Risk Analysis Portfolio Development Cost and Risk Performance Results Customer Rate Impacts Carbon Dioxide Emissions Footprint Supply Reliability Measures Class 2 DSM Decrement Analysis PARKING LOT ISSUES During the course of the public input meetings, certain concerns or questions needed additional explanation from PacifiCorp. These questions or issues were taken off-line or put in a "parking lot." PacifiCorp either responded in writing in detail to address these parking lot issues, or in many cases, addressed them in a subsequent public input meeting or workshop. PacifiCorp re- sponded to different complex questions that covered an aspects of the IRP. 138 PacifiCorp 2007 IRP Appendix F Public Input Process Additionally, for the 2007 planning cycle, PacifiCorp provided meeting summaries for each of the public meetings reflecting a synopsis of what was discussed during the meeting. These summaries can be found on the internet website (http://www.pacificorp.com/Arti- clef Article23848.html) and provide additional details on a particular IRP public meeting. PUBLICREVIEWOF.IRP DRAFT DOCUMENT This section summarizes the substantive comments on the draft IRP document submitted by IRP public participants and provides PacifiCorp s responses. The comments and responses are grouped by topic. At the public meeting held on October 31 , 2006, the company requested that parties focus on compliance with state IRP standards and guidelines when submitting comments on the draft IRP. PacifiCorp distributed the IRP draft document for public comment on April 20, 2007, with a comment due date of May 11 , 2007. The company received comments from seven parties in time to be considered for the final IRP report: Utah Public Service Commission Staff (UPSC) The Utah Committee of Consumer Services (UCCS) The Utah Division of Public Utilities (UDPU) Utah Association of Energy Users (UAE) Western Resource Advocates (WRA) The NW Energy Coalition (NWEC) Renewable Northwest Project (RNP) To characterize the comments at a high level, parties sought justification for, or cited perceived deficiencies in, (1) the scope of resources evaluated and their characterization (DSM, renew- ables, and IGCC in particular), (2) the treatment and interpretation of modeled risk factors and reliability, and (3) the decision criteria used to select preferred portfolio resources. A number of parties also submitted detailed questions and requests for supporting data. To address the written comments, PacifiCorp modified the final IRP report to include more justi- fication of its analytical. conclusions and resource decisions, and answered specific technical questions to the extent possible given the IRP filing schedule. PacifiCorp also supplemented the IRP Regulatory Compliance" appendix with two tables that outline how the company inter- preted and complied with each of the IRP standards for Oregon and Utah (Tables 1.3 and 1.4 in Appendix I). The company considered the written comments when completing these tables. Re- sponses to questions and data requests that could not be included in the final IRP report or ad- dressed in this section will be handled as separate follow-up responses. Portfolio Optimality A number of parties disagree with, or at least question, whether the preferred portfolio develop- ment process meets Utah IRP standards and Guidelines with respect to "selection of the optimal set of resources given the expected combination of costs, risk and uncertainty." For example, the UPSC asked for clarification on how the company s statement in Chapter 2 -The emphasis of 139 PacifiCorp 2007 IRP Appendix F Public Input Process the IRP is to determine the most robust resource plan under a reasonably wide range of potential futures as opposed to the optimal plan for some expected view of the future is consistent with this guideline. The UCCS states that they are not convinced of the optimality of the preferred portfolio. The UPSC and UAE believe that fixing resources for the CEM results in suboptimal resource selection. For example, the UAE states that the Group 2 portfolios appear to be subop- timal because the CEM was used to determine the build pattern of gas plants and front office transactions, while coal and wind resources were set. WRA, on the other hand, states that model results should not be used as an alternative to informed judgment and critical thinking. Response: PacifiCorp agrees with WRA that modeling results should not be used as the sole basis for determining an optimal portfolio given the multi-objective and subjective nature of the resource planning exercise. PacifiCorp s model solutions are dependent on model structure and the underlying assumptions. Thus, model results need to be interpreted in the light of real-world considerations. One of these considerations, cited in Chapter 7, are resource decision constraints resulting from new and expected state resource policies. In the context of capacity expansion modeling with the CEM, anyone model solution is only optimal for the single set of assumptions used for the associated model run and should not be considered optimal in any broader sense due to the deterministic nature of the model and the single set of input assumptions. In contrast, the role of the Planning and Risk model has been to determine the stochastic cost and risk impacts of alternative resource strategies, not to determine an optimal portfolio from a stochastic simulation standpoint. These two models together, with their different perspectives on the resource planning problem, and across a variety of input as- sumptions, have thus helped to support the overall resource decision. In regard to the impact of fixing resources on model solution optimality, PacifiCorp points out that the main purpose of the CEM is to limit the set of potential resources to a manageable size for more detailed stochastic production cost analysis and to analyze alternative futures. The CEM was successfuUy used for this purpose. As discussed in Chapter 7, development of the Group 2 portfolios was informed by both Group 1 risk analysis results and resource policy considerations. CEM optimization was only used as a portfolio refinement tool; specifically, to evaluate the tim- ing of the CCCT resources and select an optimized quantity of front office transactions resources to meet PacifiCorp ' s annual load obligation and planning reserve. Finally, PacifiCorp augmented its discussion on preferred portfolio selection in Chapter 7 by laying out the strategic justification for the portfolio. In essence, the company believes that its preferred portfolio represents a good balance of resource types with complementary strengths that together help to minimize resource risk. The idea of "robustness" under a reasonably wide range of potential futures reflects a decision goal to account for the possibility of various high- cost outcomes for customers and to avoid resource decisions that, in aggregate, lead to such an outcome being realized. The best way to accomplish this is through resource diversification which the preferred portfolio proxy resources are intended to provide. Consequently, Pacifi- Corp s definition of the optimal resource set is one that offers the best compromise of cost and risk when considering alternative futures and multiple stakeholder priorities. PacifiCorp notes that none of the state IRP standards provide definitive criteria for judging how a resource plan 140 PacifiCorp 2007 IRP Appendix F Public Input Process for a multi-state utility has achieved optimality under risk and uncertainty, and given diverse resource preferences and policies among its state jurisdictions. Plannin2 Reserve Mar2in Selection and Resource Needs Assessment A number of the parties disagreed with PacifiCorp' s use of a 12 percent planning reserve margin for its preferred portfolio, citing analysis results from the 2007 IRP that seem to support a higher margin. Others requested more justification for the selection decision. One party, UAE, endorsed the 12 percent planning reserve margin, stating that it has been adequately supported by Pacifi- Corp s cost-risk tradeoff analysis. UAE also recommended further planning margin analysis in- cluding incorporating an assessment of market response to "high carbon risk, price caps, or other externalities." The UPSC and UCCS requested an explanation of changes in certain capacity balance components relative to the components reported in the 2004 IRP, as well as cited inter- jurisdictional cost allocation issues associated with potential Energy Not Served. Response: PacifiCorp expanded its discussion on the choice of a planning reserve margin Chapter 7 ("Planning Reserve Margin Selection ). PacifiCorp s position is that the planning re- serve margin should not be considered an immutable constraint on the company s resource deci- sions given a time of rapid public policy evolution and wide uncertainty over the resulting down- stream cost impacts. Therefore, PacifiCorp now advocates a planning reserve range of 12 to 15 percent, and initially targets 12 percent for its preferred portfolio to develop some added plan- ning flexibility as public policy continues to evolve and regional resource adequacy standards are addressed. UPSC requested an explanation for the increase in wholesale sales reported in the 2007 IRP ca- pacity balance relative to that reported in the 2004 and 2004 IRP Update balances. This change is due to a reporting change for the delivery portion of exchange contracts. Exchange contract de- liveries are no longer reported in the Purchase and Renewable components as was done for the 2004 IRP and 2004 IRP Update. These delivery amounts now appear in the Sales component. Inter-jurisdictional cost allocation issues are outside of the purview of the IRP process. This in- formation will be provided as a separate response. Relationship of PacifiCorp s IRP with its Business Plan A number of the Utah parties expressed concern about how PacifiCorp s IRP is related to its Business Plan, and that PacifiCorp might not be meeting its IRP obligation under the Utah Stan- dards and Guidelines to ensure that its business plan is "directly related to its Integrated Re- source Plan." (Procedural Issue no. 9) The UDPU also pointed out a lack of sufficient informa- tion that shows that the two plans are consistent, and suggests that PacifiCorp does not comply with the Standards and Guidelines on this basis. Response: PacifiCorp s Business Plan is directly related to the IRP; the business planning proc- ess is informed by the IRP resource analysis, the action plan, and subsequent procurement activi- ties. Because the latest Business Plan was undergoing development during the latter half of the 2007 IRP cycle, it made sense to coordinate on certain resource assumptions. These assumptions are fully described in Chapter 7. Going forward, the 2007 IRP will be used to inform the next version of the Business Plan. 141 PacifiCorp 2007 IRP Appendix F Public Input Process The 2007 IRP Action Plan The UDPU believes that the draft IRP does not provide "detailed focus" on actions over the next two years as stated in Utah IRP standard 4(e). Areas that need more coverage include renewable portfolio standards, Klamath River hydroelectric relicensing, renewable resources, local renew- able projects (MEHC commitment U33), and sulfur hexafluoride emissions control (MEHC commitment 42a). Response: PacifiCorp believes that the level of detail on specific actions is comparable to what was provided in previous IRP action plans. This level of detail garnered no criticism from the UDPU in the past, and the company believes the level of detail is sufficient. Actions for acquir- ing up to 1 400 megawatts of cost-effective renewables are presented in the Renewables Action Plan, filed concurrently with this IRP in accordance with MEHC commitments. Demand-Side Mana2ement Comments centered on the lack of modeling of Class 2 (energy efficiency) programs, and the expectation that the forthcoming DSM potentials study will address parties' concerns regarding benefit capture and market potential. The UDPU identified several issues: (1) a lack of data on Class 2 DSM, (2) concern that the IRP models "do not accurately reflect the costs and benefits associated with DSM resources , citing the results of the CEM low and high DSM potential sce- nario results, (3) variable amounts of DSM and CHP resources were not subjected to risk analy- sis using the PaR model. The UDPU also requested that the company explain how the DSM po- tentials study results will be incorporated in the next IRP. The UCCS requested more explanation of the DSM resources included in the initial load and resource balance. The WRA expressed concern that an insufficient amount ofDSM has been included in the IRP. Response: PacifiCorp noted in the IRP report that Class 2 DSM could not be modeled in the CEM due to the lack of supply curve data for PacifiCorp s service territory; rather, Class 2 DSM was treated as a decrement to the load forecast as in prior IRPs, while DSM decrement values determined using stochastic production cost modeling. A discussion of the handling of Class 2 DSM is provided in Chapter 6 ("Public Utility Commission Guidelines for Conservation Pro- gram Analysis in the IRP" For the DSM potentials study, the company will receive cost-supply curves for Class 1 , Class 2 and Class 3 DSM programs, which will be input into the IRP models once they have been veri- fied and approved for use. The company will also receive a set of CHP and customer-owned standby generator resource characterizations that will be included in the models as well. Responding to the UDPU comment on performing manual DSM/CHP optimization using the stochastic PaR model, PacifiCorp notes that using the PaR in this manner is not practical given the long model run-times, which reach 16 to 18 hours. This limitation has been communicated to Utah parties during previous IRP cycles, and was one of the reasons why PacifiCorp acquired the CEM (to have an automated resource selection capability). Regarding the UCCS request for more explanation on the DSM included in the load and resource balance, Table 4.10 in Chapter 4 summarizes existing DSM program contributions to the bal- 142 PacifiCorp 2007 IRP Appendix F Public Input Process ance. Tables A.8 and A.15 in Appendix A outline the amounts and timing of Class 2 DSM load reductions. Expected Class 1 program contributions are described in Table A.13. Market Reliance. Availability. and Price Risk Several parties were concerned with the level of market purchases included in the preferred port- folio, and requested verification of market availability to support these amounts and other data and analysis. The UPSC requested that PacifiCorp provide supporting analysis of cost-risk trade- offs of market reliance versus building resources. The RNP and NWEC stated their concern that PacifiCorp overestimates the wholesale value of coal and other base load plants (and undervalues short-lead-time resources such as SCCTs and DSM) given the impact of emission performance standards and renewable portfolio standards. Re.\plJll.e: PacifiCorp added a new section in Chapter 7 that provides more information on the company s market purchase strategy and expected market availability. Regarding analysis of cost-risk tradeoff analysis of market reliance versus building, PacifiCorp refers parties to a number of risk analysis portfolios and a sensitivity study designed to directly address the cost-risk tradeoffs of assets and market reliance. These results are documented in Chapter 7. For example, the section titled "Resource Strategy Risk Reduction" describes the comparison of portfolios with and without front office transactions after 2011. The chapter also descrihes a stochastic simulation study in which PacifiCorp replaced a 2012 base load resource with front office transactions. PacitiCorp acknowledges and shares parties ' concerns over the potential market impacts of new resource constraints imposed by renewable generation requirements and CO2 emission perform- ance standards. Action plan item no. 17 (Chapter 8 , Table 8.2) addresses modeling enhancements to assist in the analysis of such issues. The company notes that such analysis capability is not present in existing market models that are designed to simulate integrated system operation. PacitiCorp has been exploring CEM customization possibilities with the model vendor, Global Energy Decisions. SCOOt' of Resource Analvsis Most of the parties identified resources that PacifiCorp did not model but thought it should have or clse requested an explanation for why they were not modeled. Examples include solar, geo- thenna!. and storage technologies. The UCCS requested that PacifiCorp investigate an approach that enahles comparable treatment of an technologies throughout the modeling process even they have heen excluded for modeling purposes on the basis of screening criteria. The UPSC questioned why the company is not addressing retrofits, retirements, and distributed technologies as resource options. The UDPU inquired as to PacifiCorp plans to build a landfin gas power plant in the near future. The UPSC and UCCS questioned why geothermal was not modeled given that it has the lowest reported total resource cost in Tables 5.3 and 5.4 (The UPSC also questioned the difference in geothermal capital costs between the value reported in the IRP and the Blundell economic study.) The WRA stated that technology risk should not be used as a screen to eliminate resources from further consideration, and also caned for more robust analysis of CHP potential. The UAE recommended that the planning horizon be extended to facilitate analysis of nuclear and other long-lead-time resources. Both the NWEC and WRA stated that the 143 PacifiCorp 2007 IRP Appendix F Public Input Process CO2 risk analysis was flawed by not including IGCC with carbon capture and sequestration as an appropriately modeled resource (i., allowing the CEM to select carbon capture and sequestra- tion for an IGCC plant once it becomes economic to do so). Response: A summary of the process for selecting resources to include in the IRP models is pro- vided in Tables 1.3 and 1.4 in Appendix I (See the response to Oregon Guideline l.l in Table 1.3, and the response to Utah Standard 4.b.ii in Table 1.4). As noted, PacifiCorp intends to inves- tigate a CEM modeling process that accommodates a broader range of technologies within the limitations of the company s IRP models. PacifiCorp will consider retirements and retrofits as resource options in future IRPs. Consideration of these resource options and others will be made in the context of an overall review of resource potentials, data availability, technical feasibility, and modeling constraints. Concerning the observation on the low reported geothermal total resource cost, PacifiCorp ex- panded its discussion on the geothermal project cost characterization and treatment of the renew- able production tax credit for geothermal projects (Chapter 5 , ' Other Renewable Resources ). On the differences between reported geothermal capital costs in the IRP and Blundell economic study, PacifiCorp notes that the UCCS submitted a formal data request on May 16 2007 on this issue, to which the company will respond separately from this IRP report. Regarding the consideration of technology risk as a factor in resource screening, PacifiCorp points out this is just one factor that was used to develop the modeled resource list. PacifiCorp agrees that technology risk should not be used as a screen to exclude resources from further con- sideration. Other factors considered by the company included the outlook for commercial matur- ity during the 10-year investment horizon that was the focus of this IRP, and most importantly, practical modeling considerations of the CEM. PacifiCorp quickly approached the resource limit recommended by the model vendor and began to scale back resources and define generic proxy resources for front office transaction and renewables. The associated learning experience wi11 be useful as the company addresses the anticipated expansion of resource options for the next IRP. Regarding landfill gas plants , PacifiCorp has reviewed potential sites for such projects in the Rocky Mountain Power and Pacific Power service territories, and selected two sites in Oregon for which feasibility studies have been conducted. The initial findings and recommendation are undergoing review. The company is also looking at five other landfill sites (one in Washington and four in Utah) for possible feasibility analysis. As to the UAE's recommendation to extend the planning horizon to facilitate analysis of nuclear and other long-lead-time resources, the company will consider this change as it formulates its next IRP modeling plan. Concerning the modeling of IGCC with carbon capture and sequestration, PacifiCorp notes that the current version of the CEM does not allow the modeling of plant retrofits such as carbon cap- ture and sequestration. However, the company is acquiring a CEM model upgrade that includes this modeling capability, and expects to implement this functionality in time for the next IRP. Nevertheless, PacifiCorp disagrees with the WRA's contention that the CO2 risk analysis is in- herently flawed to the extent that it "should be completely reworked before any conclusions must 144 PacifiCorp 2007 IRP Appendix F Public Input Process be drawn" because of the way IGCC-based carbon capture and sequestration was addressed in the IRP models. PacifiCorp s modeling of IGCC for this IRP first looked at the ability of carbon- capture-ready IGCC to stand on its own merits, and then performed various sensitivity analyses to investigate the potential cost impacts of adding carbon capture and sequestration. PacifiCorp believes that the uncertainties associated with carbon capture and sequestration are too great to consider it as an investment that customers and investors are willing to commit to and pay for in the period covered by the IRP action plan. The IGCC analyses performed by the company sup- port the view that a decision to add IGCC to the company s resource portfolio will not be driven by modeling considerations, but rather as an outcome of public policy debates and collaborative public-private development ventures such as the one recently announced by the Wyoming Infra- structure Authority and PacifiCorp. Load Forecast A number of parties requested additional explanation for why the March 2007 Utah load forecast shows a dip in the growth in 2008-2009 relative to the May 2006 forecast. The UCCS requested justification for why PacifiCorp relies on an expected (1 in 2) load forecast for planning, and inquires as to how planning to a 90% confidence interval would change the company s resource position and resource selection decisions. Regarding the higher load growth expected for Wyo- ming, the WRA expressed concern about committing resources to uncertain and volatile extrac- tive industry loads, which account for the higher forecasted load growth. The UPSC requested the insertion of additional load forecast information in the IRP report. Response: PacifiCorp accounts for load forecast error in its IRP by using a planning reserve margin. Planning to a 90 percent confidence internal would lessen the need to plan for unex- pected load growth and, therefore, would likely reduce the level of planning reserve margin re- quired by the company. PacifiCorp is well aware of the volatile nature of extractive industry loads, and therefore applies a discount factor to the load forecasts contained in industrial customer service requests. Forecasts for the new Wyoming loads were reduced by 30 percent compared to estimates provided by cus- tomers. The load discount is based on rankings of the likelihood of occurrence of the customers loads and the probability associated with that likelihood. Additionally, the company looks at the market conditions that will impact each industry, supply and demand in the industry, and other events that may impact the industry such as substitution impacts. Concerning the requested load forecast information, PacifiCorp made the following report modi- fications to Chapter 4 and Appendix A: Data for 2006 was added to both the energy and coincident peak capacity forecasts tables in Chapter 4, as well as to each state table in Appendix A. . A column was added to Table 4.5 in Chapter 4 that shows loads for the Southeast Idaho re- gIOn. . A new section , " Jurisdictional Peak Load Forecast " was added in Chapter 4 with informa- tion similar to that reported for the coincident peak. . An explanation for the Utah load growth dip was added to Chapter 4 ("May 2006 Load Fore- cast Comparison 145 PacifiCorp 2007 IRP Appendix F Public Input Process Carbon Dioxide Re2ulatory Risk Analvsis The WRA cited a number of concerns with PacifiCorp s CO2 risk modeling approach. First, they questioned the value of using a $O/ton CO2 cost adder and cited the $8/ton medium adder case as also "remote over the long term." They advocate studying carbon costs in the range of plus or minus $30/ton. Second, they view the use of a year-2000 emissions cap under a cap-and-trade mechanism as unrealistic. Third, they believe that adding two coal resources by 2014 does not provide sufficient diversity to endure future carbon regulation. Fourth, they question Pacifi- Corp s treatment of CO2 regulation as a scenario risk and propose that the company model it probabilisticany. The UAE claims that PacifiCorp failed to capture the impact of higher gas prices and lower electricity demand attributable to potentiany high carbon taxes. The RNP views PacifiCorp s greenhouse gas mitigation strategy as "insufficient for the task " and "is hardly an active strategy at alL" The RNP also faults PacifiCorp for not modeling a portfolio that decreases overall CO2 emissions, or that has no coal resources. Respollse: PacifiCorp is required, via the Oregon IRP Standards and Guidelines, to assess envi- ronmental externality costs using a $O/ton CO2 cost adder. Also, UPSC staff requested that the company include the $0 adder as part of a business-as-usual scenario case. The use of a single point estimate of around $30/ton, if that is what is being suggested, is not consistent with Oregon or Utah IRP guidelines that can for a number of specific adder values (in the case of Oregon) or a range of estimated external costs (in the case of Utah). PacifiCorp models a $38/ton adder (in 200X dollars). Regarding the baseline cap and other assumptions for specifying a CO2 regulatory framcwork, the company win revisit them as part of its next IRP process and as a result of the outcomc of the Oregon Public Utility Commission proceeding on CO2 risk in the IRP (Docket UM 302). PacifiCorp does not understand WRA's point regarding the use of stochastic methods to model CO2 regulatory risks. WRA supports stochastic analysis over scenario analysis, but then concedes that stochastic analysis is too complicated and should therefore be discounted or aban- doned in favor of informed judgment. From this logic, PacifiCorp is not clear what modeling approach thc WRA finds acceptable for conducting CO2 risk analysis. Regarding the claim that the company has not captured gas price risk due to higher carbon taxes PacifiCorp notes that the gas price and electricity price forecasts used for the CO2 cost adder scenarios account for the increased CO2 adder values. See the text box titled "Modeling the Im- pact of CO2 Externality Costs on Forward Electricity Prices" in the Environmental Externality Cost section of Chapter 6. Finally, PacifiCorp updated Chapter 7 of the draft IRP report with a portfolio study that entailed constraining CEM system-wide resource selection to only those resources that could meet a Cali- fornia-style greenhouse gas emission performance standard. One of the resource choices was lGCC with carbon capture and sequestration. Transmission The UDPU had several transmission questions. First, they question whether transmission wheel- ing as a potential solution to transmission needs is appropriate given that it "fluctuates with the markcC'. The UDPU also stated that the IRP draft does not address renewable portfolio standard (RPS) impacts on transmission planning or the National Governor s Conference positions on transmission planning and resources, and asks if these issues are being considered. Finally, they 146 PacifiCorp 2007 IRP Appendix F Public Input Process asked for clarification on the use of 500-megawatt blocks for specifying certain transmission paths in the CEM (Bridger-Ben Lomond; Mona-Utah North; Wyoming-Bridger East; Utah North-West Main; Utah South-Four Comers). The UAE expressed support for the use of trans- mission additions to delay supply-side resources, but was not clear if transmission was put on an equal footing with generation. Response: PacifiCorp s view is that it is prudent to include aU reasonable transmission options for consideration given the complexities associated with building transmission facilities. Regard- ing RPS requirements, the company is investigating the consequences of these new regulations. Regarding specification of the above referenced transmission resources, these resources are con- sidered as proxies for a variety of potential projects to support new generation and facilitate power transfers in the east control area. Specifying 500-megawatt blocks for a proxy transmis- sion resource was an efficient method to express incremental transmission investment for the CEM to select. Transmission resources were treated on a comparable basis with respect to generation resources. The CEM makes decisions to build generation or transmission units at a given resource site in a given year. The amortized cost of both transmission and generation capacity expansion is in- cluded in the model's PVRR minimization objective function. Miscellaneous Two parties, NWEC and the RNP, advocated that the company rely on an upper-tail measure of stochastic risk rather than risk exposure (stochastic upper-tail mean PVRR minus the overaU stochastic mean PVRR for 100 Monte Carlo model iterations). The RNP states that the IRP does not adequately consider the capital cost risks of pulverized coal plants, and cites one example of a coal plant construction estimate that increased by 50 percent over original estimates. Regarding the Intermountain Power Plant Unit 3 project (IPP 3), the UDPU requested a status update and an indication of the company s current intentions regarding the project. The WRA also believes that an in-service date of 20 12 for IPP3 or any other coal plant is unrealistic. The UPSC requested detailed information on the company s commitment to invest $1.2 biUion on cost-effective poUution control. Specific requests include the foUowing: Explanation of "how and in what forum the Company plans to perform the cost-benefit analysis for these investments, and should such analysis be part of the Integrated Resource Planning evaluation? Does the $1.2 billion include mandatory requirements, i., mercury control on existing plants? Does it include those existing plant retrofit projects which are necessary for permit require- ments to add new units at facilities? Clarify and provide a table showing the value, project description, and location of the in- vestments. 147 PacifiCorp 2007 IRP Appendix F Public Input Process Response: PacifiCorp has added the upper-tail mean along with the 95 th percentile in the Chap- ter 7 tables that report stochastic risk measures for the risk analysis portfolios. The company notes that risk analysis portfolio rankings are generaUy invariant with respect to the stochastic risk measures. PacifiCorp has been tracking construction costs for aU new resource types, and has seen in- creases in costs for aU resources. This fact is mentioned in Chapter 5. The company will use the bid information received for its Base Load Request For Proposal to help inform estimation of new resource capital costs for the 2007 IRP Update. Regarding the status ofIPP 3 , PacifiCorp and the other Intermountain Power Plant Unit 3 (IPP 3) participants acknowledge that there are some air permit challenges by certain parties and con- tractual complications associated with Los Angeles Department of Water and Power that need to be resolved. PacifiCorp and the IPP 3 development team remain focused on working through these issues and intend to exercise their development right relating to construction of the facility. The IPP 3 development team is currently evaluating bids from major engineering procurement and construction contractors. IPP 3 remains a component in filling PacifiCorp s needs for low cost reliable resources, and the plant remains as a benchmark resource for 2012. The UPSC's request for PacifiCorp s poUution control investment plans will be provided as a separate response. CONT ACT INFORMATION PacifiCorp s IRP internet website contains many of the documents and presentations that support the 2003 , 2004 and 2007 Integrated Resource Plans. To access it, please visit the company website at http://www.PacifiCorp.com , click on the menu "News & Info" and select "Integrated Resource Planning PacifiCorp requests that any informal request be sent in writing to the following address or email address below. PacifiCorp IRP Resource Planning 825 N.E. Multnomah, Suite 600 Portland, Oregon 97232 Electronic Email Address: IRP(d~PacifiCorp.com Phone Number: (503) 813-5245 148 PacifiCorp 2007 IRP Appendix G - Performance on 2004 IRP Action Plan APPENDIX G - PERFORMANCE ON 2004 IRP ACTION PLAN INTRODUCTION This appendix summarizes the performance on the 2004 IRP action plan filed in January 2005. PacifiCorp provided an update of this action phin in November 2005 as part of the "2004 IRP Update" filed with state commissions in November 2005. The 2004 IRP Update action plan also incorporated updates to several action items in the 2004 IRP action plan. Table G.1 shows the progress of the original and updated action items listed in Table 5.2 of the 2004 IRP Update document (Chapter 5 , page 46). 149 Pa c i f i C o r p 20 0 7 I R P Ta b l e G . I - S t a t u s U p d a t e o n 20 0 4 I R P A c t i o n P l a n Su p p l y - Si d e Re n e w a b l e s FY 2 0 0 6 - 20 1 5 40 0 DS M Cl a s s 2 FY 2 0 0 6 - 20 1 5 45 0 M W a Ap p e n d i x G - Pe r f o r m a n c e o n 2 0 0 4 I R P A c t i o n P l a n s Sy s t e m Wi n d Sy s t e m 10 0 M W de c r e m e n t s a t va r i o u s l o a d sh a p e s Co n t i n u e t o a g g r e s s i v e l y pu r s u e c o s t - e f f e c t i v e re n e w a b l e r e s o u r c e s th r o u g h c u r r e n t a n d fu t u r e R F P ( s ) . Us e d e c r e m e n t v a l u e s t o as s e s s c o s t - e f f e c t i v e b i d s in D S M R F P ( s ) . A c q u i r e th e b a s e D S M ( P a c i f i - Co r p a n d E T O c o m - bi n e d ) o f 2 5 0 M W a a n d up t o a n a d d i t i o n a l 2 0 0 MW a i f c o s t - e f f e c t i v e pr o g r a m s c a n b e f o u n d th r o u g h t h e R F P p r o c e s s . Pa c i f i C o r p h a s a c q u i r e d 3 4 6 me g a w a t t s o f t h e 4 0 0 m e g a w a t t ta r g e t s e t f o r 2 0 0 7 , a s o f A p r i l 20 0 7 . T h e c o m p a n y p l a n s t o a c - qu i r e a l l 1 , 4 0 0 m e g a w a t t s b y 2 0 1 0 an d t o a c q u i r e a n a d d i t i o n a l 6 0 0 me g a w a t t s f r o m 2 0 1 1 t h r o u g h 20 1 3 . . T h e c o m p a n y c o n d u c t e d a c l a s s 2 DS M d e c r e m e n t s t u d y f o r t h e 20 0 7 I R P . T o a d d r e s s r i s k , t h i s st u d y u s e d s t o c h a s t i c s i m u l a t i o n wi t h a n $ 8 / t o n C O 2 a d d e r . Pa c i f i C o r p a l s o i n c r e a s e d t h e nu m b e r o f l o a d s h a p e s f r o m e i g h t to t w e l v e . . T h e 2 0 0 5 DS M R F P t o p r o c u r e Cl a s s 1 , 2 a n d 3 r e s o u r c e s w a s is s u e d a c c o r d i n g t o t h e a c t i o n pl a n i n t h e 2 0 0 4 I R P ( r e f e r e n c e Ta b l e 9 . 3) . T h e R F P w a s s t r u c - tu r e d t o s o l i c i t p r o p o s a l s f o r b o t h sp e c i f i c r e s o u r c e s t y p e s : a c o m - pr e h e n s i v e r e s i d e n t i a l e q u i p m e n t an d s e r v i c e p r o g r a m a s w e l l a s an " al l c o m e r s " r e q u e s t f o r e a c h re s o u r c e t y p e . . T h e Ho m e E n e r g y S a v e r s p r o - gr a m w a s f i l e d a n d a p p r o v e d i n 20 0 6 i n I d a h o , W a s h i n g t o n a n d Ut a h a n d i s b e i n g p r o p o s e d i n Ca l i f o r n i a a n d W y o m i n g i n 20 0 7 . O n M a r c h 2 0 , 2 0 0 7 , t h e Ut a h P u b l i c S e r v i c e C o m m i s s i o n ap p r o v e d m o d i f i c a t i o n s t o t h e 15 0 Pa c i f i C o r p 20 0 7 I R P Ap p e n d i x G - Pe r f o r m a n c e o n 2 0 0 4 I R P A c t i o n P l a n s Di s t r i b u t e d Ge n e r a t i o n Di s t r i b u t e d Ge n e r a t i o n CH P FY 2 0 1 0 (s u m m e r of C Y 20 0 9 ) a n d FY 2 0 1 3 (C Y 2 0 1 2 ) nl a Sy s t e m Tw o 4 5 M W un i t s u s i n g NR E L c o s t es t i m a t e s St a n d b y Ge n e r a t o r s FY 2 0 1 0 (s u m m e r of C Y 20 0 9 ) a n d FY 2 0 1 3 (C Y 2 0 1 2 ) nl a Ut a h 75 M W i n Ut a h In c l u d e C H P a s e l i g i b l e re s o u r c e s i n s u p p l y - s i d e RF P s . In c l u d e a p r o v i s i o n f o r St a n d b y G e n e r a t o r s i n su p p l y - s i d e R F P s . I n v e s - ti g a t e , w i t h A i r Q u a l i t y Of f i c i a l s , t h e v i a b i l i t y o f th i s r e s o u r c e o p t i o n . St a t u s . 20 0 7 E n e r g y S t a r N e w H o m e s Pr o g r a m a n d i n A p r i l 2 0 0 7 e x - te n d e d t h e C o o l C a s h a i r c o n d i - ti o n e r e f f i c i e n c y p r o g r a m . . T h e c o m p a n y al s o a c c e p t e d a pr o p o s a l t o e n h a n c e b u s i n e s s pr o g r a m p e n e t r a t i o n o f t h e n e w co n s t r u c t i o n m a r k e t . I n a d d i t i o n on e p r o g r a m p r o p o s a l f r o m t h e 20 0 5 D S M R F P i s s t i l l u n d e r co n s i d e r a t i o n . I t w i l l b e e v a l u - at e d f u r t h e r u s i n g u p d a t e d v a l u a - ti o n i n f o r m a t i o n d e r i v e d t h r o u g h th e 2 0 0 7 I R P p l a n n i n g p r o c e s s a s we l l a s r e s u l t s f r o m t h e s y s t e m - wi d e D S M p o t e n t i a l s t u d y r e s u l t s du e i n J u n e 2 0 0 7 . Co n t i n u e t o p u r c h a s e C H P o u t p u t as Q u a l i f y i n g F a c i l i t i e s ( Q F ) p u r - su a n t t o P U R P A r e g u l a t i o n s . T h e 20 0 7 p r e f e l T e d p o r t f o l i o c o n t a i n s an a d d i t i o n a l 1 0 0 M W o f C H P re s o u r c e s , c i t e d i n 2 0 0 7 I R P a c t i o n Ia n i t e m n o . 5 . Th e f i n a l B a s e L o a d R F P d o e s n o t co n t a i n a n E a s t s i d e s t a n d - by g e n - er a t i o n r e s o u r c e e x c e p t i o n d u e t o Ut a h D i v i s i o n o f A i r Q u a l i t y r e g u - la t i o n s o n d i e s e l g e n e r a t i o n e m i s - si o n s s t a n d a r d s . P a c i f i C o r p w i l l co n t i n u e t o i n v e s t i g a t e a l t e r n a t i v e s fo r s t a n d - by g e n e r a t o r s a s a r e - so u r c e . P a c i f i C o r p m e t w i t h P o r t - la n d G e n e r a l E l e c t r i c t o d i s c u s s th e i r s t a n d - en e r a t i o n r o r a m . 15 1 Pa c i f i C O I p 20 0 7 I R P Ap p e n d i x G Pe r f o r m a n c e o n 2 0 0 4 I R P A c t i o n P l a n s Si z e (R o u n d e d Il I l h e Ac t i o n Ad d i t i o n Re s o u r c e ne a r e s l 5 0 IR P Re s o u r c e 20 0 4 IR P Ac t i o n P l a n It e m T'O T" D e Tl m l n ! ! MW ) L. o c a t i o n E, o al u a t e d De s c r i p t i o n St a t u s Th e c o m p a n y l a u n c h e d a c o m m e r - ci a l l i g h t i n g c o n t r o l p r o g r a m ( L o a d Li g h t e n e r ) i n U t a h i n F e b r u a r y 20 0 5 . H o w e v e r , t h e p r o g r a m w a s te r m i n a t e d i n A u g u s t 2 0 0 6 d u e t o po o r p r o g r a m p e r f o n n a n c e . T h e co m p a n y e x p a n d e d t h e I d a h o i r r i - ga t i o n l o a d m a n a g e m e n t p r o g r a m an d e x t e n d e d t h e I d a h o i r r i g a t i o n lo a d m a n a g e m e n t p r o g r a m i n t o FY 2 0 0 9 Pr o c u r e c o s t - e f f e c t i v e Ut a h i n t h e s p r i n g of 20 0 7 , a n d (s u m m e r Ir r i g a t i o n su m m e r l o a d c o n t r o l co n t i n u e s t o i n v e s t i g a t e t h e p o s s i - DS M Cl a s s I of C Y Ut a h Lo a d C o n t r o l pr o g r a m i n U t a h b y t h e bl e e x p a n s i o n of Ut a h ' s a i r c o n d i - ti o n e r l o a d c o n t r o l p r o g r a m b e y o n d 20 0 8 ) su m m e r of 20 0 8 . 10 0 M W s ( a t t h e g e n e r a t o r ) . I n ad d i t i o n , t h e c o m p a n y i s s t i l l ev a l u a t i n g , w i t h i n t h e 2 0 0 7 p l a n - ni n g p r o c e s s , t w o ot h e r Cl a s s I pr o p o s a l s r e c e i v e d t h r o u g h t h e 20 0 5 D S M R F P . L i k e t h e C l a s s 2 pr o p o s a l , t h e c o m p a n y w i l l u t i l i z e th e s y s t e m - w i d e D S M p o t e n t i a l st u d y r e s u l t s t o h e l p f u r t h e r a s s e s s th e v i a b i l i t y of th e r e m a i n i n g p r o - po s a l s . Th e 2 0 0 5 D S M R F P g e n e r a t e d Cl a s s 1 l o a d c o n t r o l p r o p o s a l s ta r g e t i n g ou r we s t e r n s y s t e m . T h e Pr o c u r e c o s t - e f f e c t i v e pr o p o s a l s w e r e of va r i o u s s i z e s a n d FY 2 0 0 9 su m m e r l o a d c o n t r o l we r e s i g n i f i c a n t l y m o r e e x p e n s i v e DS M Cl a s s I (s u m m e r OR / W A f Ir r i g a t i o n pr o g r a m i n O r e g o n th a n a n t i c i p a t e d . T h e p r o p o s a l s of C Y Lo a d C o n t r o l Wa s h i n g t o n , a n d / o r un d e r w e n t f u r t h e r a n a l y s i s w i t h i n 20 0 8 ) Ca l i f o r n i a b y t h e s u m m e r th e 2 0 0 7 I R P m o d e l i n g p r o c e s s a n d of 20 0 8 . we r e d e t e n n i n e d n o t t o b e c o s t - ef f e c t i v e . H o w e v e r , t h e 2 0 0 7 I R P mo d e l i n g d i d s e l e c t t h e l e s s e r c o s t ir r i g a t i o n l o a d m a n a g e m e n t o r o - 15 2 Pa c i f i C o r p 20 0 7 I R P Ap p e n d i x G - Pe l f o r m a n c e o n 2 0 0 4 I R P A c t i o n P l a n s Ac t i o n It e m Tr a n s m i s s i o n Su p p l y - Si d e Tr a n s m i s s i o n Pa t h - C U p - gr a d e Co a l r e - so u r c e Re g i o n a l Tr a n s m i s s i o n FY 2 0 1 1 (s u m m e r of C Y 20 1 0 ) 30 0 ID / U T Pa t h - C U p - gr a d e FY 2 0 1 3 (s u m m e r of C Y 20 1 2 ) 60 0 Ut a h Pu l v e r i z e d Co a l P l a n t FY 2 0 1 3 an d b e - yo n d Tr a n s m i s s i o n fr o m W y o - mi n g t o U t a h n/ a Sy s t e m Pu r s u e u p g r a d e o f t r a n s - fe r c a p a b i l i t y f r o m I d a h o to U t a h . Pr o c u r e a h i g h c a p a c i t y fa c t o r r e s o u r c e i n o r de l i v e r e d t o U t a h b y t h e su m m e r o f C Y 2 0 1 2 . Co n t i n u e t o w o r k w i t h ot h e r r e g i o n a l e n t i t i e s t o de v e l o p G r i d W e s t . Co n t i n u e t o a c t i v e l y pa r t i c i p a t e i n r e g i o n a l tr a n s m i s s i o n i n i t i a t i v e s (e . g. R M A T S , N T A C ) St a t u s gr a m w h i c h t h e c o m p a n y i n t e n d s t o in v e s t i g a t e i m p l e m e n t i n g b e g i n - ni n g a s e a r l y a s 2 0 1 0 . Pa t h C t r a n s m i s s i o n s e r v i c e r e - qu e s t s h a v e b e e n c o m p l e t e d f o r t h e sy s t e m i m p a c t s t u d i e s a n d a r e cu r r e n t l y u n d e r t h e F a c i l i t y S t u d y ph a s e . G r i d W e s t w a s d i s s o l v e d a s of J u n e 2 0 0 6 . O t h e r r e g i o n a l e n t i - ti e s c o n t i n u e t o p u r s u e r e g i o n a l tr a n s m i s s i o n p l a n n i n g i n i t i a t i v e s . Pl e a s e s e e C h a p t e r 3 f o r a d d i t i o n a l tr a n s m i s s i o n r e l a t e d t o i c s . Th e B a s e L o a d R F P w a s i s s u e d o n Ap r i l 5 , 2 0 0 7 f o r u p t o 1 70 0 M W fo r d e l i v e r y i n 2 0 1 2 , 2 0 1 3 , a n d / o r 20 1 4 . T h e c o m p a n y i s c u r r e n t l y i n th e b i d d e r s u b m i s s i o n p h a s e o f t h e RF P p r o c e s s . T h e R F P c o n t a i n s tw o b e n c h m a r k c o a l p l a n t s a n d a n IG C C o p t i o n f o r b i d d e r s . R e - so u r c e s f o r 2 0 1 2 a n d 2 0 1 4 a r e be i n g r e q u e s t e d w i t h e x c e p t i o n s f o r lo a d c u r t a i l m e n t a n d Q u a l i f y i n g Fa c i l i co n t r a c t s . Pa c i f i C o r p i s e n g a g e d i n a n u m b e r of r e g i o n a l t r a n s m i s s i o n p l a n n i n g in i t i a t i v e s i n t e n d e d t o a d d r e s s tr a n s m i s s i o n i s s u e s a n d o p p o r t u n i - ti e s . W E C C r e c e n t l y l a u n c h e d t h e Tr a n s m i s s i o n E x p a n s i o n P l a n n i n g Po l i c y C o m m i t t e e ( T E P P C ) t o ad d r e s s i n t e r c o n n e c t i o n - w i d e tr a n s m i s s i o n e x p a n s i o n p l a n n i n g . Gr i d W e s t w a s d i s s o l v e d a s o f J u n e 20 0 6 . A r o u ca l l e d t h e N o r t h e r n 15 3 Pa c i f i C o r p 20 0 7 I R P Ap p e n d i x G - Pe r f o r m a n c e o n 2 0 0 4 I R P A c t i o n P l a n s IR P P r o c e s s Mo d e l i n g nl a il i a il i a In c o r p o r a t e C a p a c i t y Ex p a n s i o n M o d e l i n t o po r t f o l i o a n d s c e n a r i o an a l y s i s . 20 0 7 I R P Ti e r T r a n s m i s s i o n G r o u p w a s fo r m e d t o f a c i l i t a t e r e g i o n a l p l a n - ni n g i n t h e a b s e n c e o f G r i d W e s t an d t h e R o c k y M o u n t a i n A r e a Tr a n s m i s s i o n S t u d y ( R M A T S ) . Pl e a s e s e e C h a p t e r 3 f o r a d d i t i o n a l tr a n s m i s s i o n r e l a t e d t o i c s . Pa c i f i C o r p p l a c e d t h e C a p a c i t y Ex p a n s i o n M o d u l e ( l i c e n s e d b y Gl o b a l E n e r g y D e c i s i o n s I n c . ) i n t o fu l l p r o d u c t i o n f o r t h e 2 0 0 7 I R P pr o c e s s . S e e C h a p t e r s 6 a n d 7 f o r mo r e i n f o n n a t i o n o n h o w t h i s t o o l wa s u s e d i n t h e 2 0 0 7 I R P . 15 4 PacifiCorp 2007 IRP Appendix H Distribution Deferral Benefit of CHP APPENDIX H - DEFERRAL OF DISTRIBUTION INFRASTRUCTURE WITH CUSTOMER-BASED COMBINED HEAT AND POWER GENERATION INTRODUCTION As part of Oregon Order 06-029, PacifiCorp was asked to examine the potential for customer- based high-efficiency combined heat and power (CHP) resources to defer investment in the dis- tribution system to meet load growth. The specific situation the company was ordered to exam- ine was a case where a customer utilizing CHP, sized to exactly meet the customer load, would be connected to the distribution system as normal, but no additional infrastructure would be added to accommodate the additional load. In the event of an outage to the generation, the cus- tomer would be served by PacifiCorp s distribution system, as long as capacity was available; if this outage occurred at a time where the distribution infrastructure was incapable of serving the additional load for whatever reason, the customer would be automaticaUy disconnected. The intent of this appendix is to first determine what distribution infrastructure deferrals would be possible for an interruptible customer with on-site generation as described above, and then to compare the cost of those deferrals to a traditional customer taking firm service and having no on-site generation. For the purposes of the comparison, it is assumed that five megawatts of cus- tomer load is to be added to PacifiCorp s west control area 12.5 kilovolt distribution system (ei- thcr a ncw load or a customer adding load). TRADITIONAL CONNECTION Extending service to a five megawatt customer to the company s distribution system is a typical industrial ncw connection for PacifiCorp, a request which occurs many times per year. Gener- ally a customer receives an allowance for their connection facilities equal to one year s expected revenue; any expenditure beyond this is an out-of-pocket expense for the customer. For a cus- tomer of this size, these connection requirements typicaUy range from $50 000 to $150 000, not inclusivc of upstream reinforcements necessary to accommodate new load. The expected reve- nue for a five megawatt, primary-metered customer ranges from $400 000 to $600 000 per year which means that usuaUy all of the cost is borne by PacifiCorp. The upstream reinforcements can range from $500 000 for new feeder infrastructure to more than $2 500 000 if an additional substation is required. These are also at the company s expense. The total cost of adding a new five megawatt customer is estimated to range from $550 000 to $2.650.000 in this example. AU of these connection expenses are considered capital improve- ments and are depreciated over 50 to 60 years, depending on the type of facility. GENERA TIONCONNECTION If a customer decides to serve its electricity needs with an on-site generating facility, along with being interrupted when their own generating facility is down, then the company would not ex- 155 PacifiCorp 2007 IRP Appendix H Distribution Deferral Benefit of CHP pect any revenues. Therefore, the company would not pay any connection costs for this customer and would save $50 000 to $150 000 of interconnection costs describe above. Additionally, because this customer would be interruptible if the existing distribution infrastruc- ture could not serve the customer for some reason (under-voltage, over-current, etc.) during a generator outage, no additional infrastructure would be necessary. This may allow the company to defer the $500 000 to $2 500 000 investment previously identified, depending on the current loading levels on the feeder. For example, PacifiCorp rates its 12.5 kilovolt circuits for approxi- mately ten megawatts, or twice the load that is expected to be added as a result of this customer connection. Therefore, any feeder already loaded to 50 percent or more of its rating would need to be upgraded in order to provide traditional service to this particular customer. Feeders loaded below this threshold would not require upgrade. Examining Oregon s feeder population, we find that about 61 percent of PacifiCorp Oregon circuits are currently loaded at or above 50 percent. If the five megawatt customer were to be located on one of these feeders, then there could be deferred investment of $500 000 to $2 500 000. If the five megawatt customer were to be located on one of these feeders, then there could be deferred investment of $500 000 to $2 500 000. PacifiCorp would not realize any additional capital investment savings for customers located on the other 39 percent of feeders. CONCLUSION The comparison above shows that a five megawatt load, coupled with a five megawatt customer- sited generation unit (customer-owned or not) located on a typical 12.5 kilovolt feeder in Oregon can potentially offset estimated connection costs of $50 000 to $150 000 under current line ex- tension policies. In addition, there may be an opportunity to avoid infrastructure costs, at an es- timated amount of $500 000 to $2 500 000. These savings would only be available if the cus- tomer agreed to be interrupted when their generation is reduced or off-line, and the distribution system is not capable of being used to serve their load. Actual savings, if any, from a customer in a situation similar to the one described in this example, would be based on their particular circumstances. 156 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance APPENDIX I - IRP REGULATORY COMPLIANCE BACKGROl)"ND Least-cost planning (i., Integrated Resource Planning) guidelines were first imposed on regu- lated utilities by state commissions in the 1980s. Their purpose was to require utilities to con- sider all resource alternatives, including demand-side measures, on an equal comparative footing, when making resource planning decisions to meet growing load obligations. Integrated resource planning has expanded since then to incorporate the consideration of risk, uncertainty, and envi- ronmental externality costs into the resource evaluation framework. Planning rules were also intended to require utilities to involve regulators and the general public in the planning process prior to making resource decisions. PacifiCorp prepares an IRP for the states in which it provides retail service. While the rules among the jurisdictional states vary in substance and style concerning IRP submission require- ments, there is a consistent thread in intent and approach. PacifiCorp is required to file an IRP every two years with most state commissions. The IRP must look at all resource alternatives on a level playing field and propose a near-term action plan that assures adequate supply to meet load obligations at least cost, while taking into account risks and uncertainties. The IRP must be developed in an open, public process and give interested parties a meaningful opportunity to par- ticipate in the planning. This appendix provides a discussion on how the 2007 IRP complies with the various state com- mission IRP Standards and Guidelines, 2004 IRP acknowledgement requirements, and other commission decisions. Included at the end of this appendix are the fonowing tables: Table 1.1 - Provides an overview and comparison of the rules in each state for which IRP submission is required. Table 1.2 - Provides a description of how the 2004 IRP acknowledgement requirements and other commission requests were addressed. Table 1.3 - Provides an explanation of how this plan addresses each of the items contained in the new Oregon IRP guidelines issued in January 2007. Table 1.4 - Provides an explanation of how this plan addresses each of the items contained in the Utah Public Service Commission IRP Standard and Guidelines issued in June 1992. GENERAL COMPLIANCE PacifiCorp prepares the IRP on a biennial basis and files the IRP with the state commissions. The preparation of the IRP is done in an open public process with consultation between an inter- ested parties, including commissioners and commission staff, customers, and other stakeholders. This open process provides parties with a substantial opportunity to contribute information and ideas in the planning process, and also serves to inform an parties on the planning issues and 3 California and Wyoming requirements are not summarized in Table 1.1. The Wyoming requirements are discussed in the chapter text. California guidelines exempt a utility with less than 5QO OOO customers in the state from filing an IRP. 157 PacifiCorp 2007 IRP Appendix I IRP Regulatory Compliance approach. The public input process for this IRP, described in Volume 1 , Chapter 2, as wen as in Appendix F, fully complies with the IRP Standards and Guidelines. The IRP provides a framework and plan for future actions to ensure PacifiCorp continues to pro- vide reliable and least-cost electric service to its customers. The IRP evaluates, over a twenty- year planning period, the future loads of PacifiCorp customers and the capability of existing re- sources to meet this load. To fin any gap between changes in loads and existing resources, the IRP evaluates an available resource options, as required by state commission rules. These resource alternatives include sup- ply-side, demand-side, and transmission alternatives. The evaluation of the alternatives in the IRP, as detailed in Chapters 6 and 7, meets this requirement and includes the impact to system costs, system operations, supply and transmission reliability, and the impacts of numerous risks uncertainties and externality costs that could occur. To perform the analysis and evaluation PacifiCorp employs a suite of models that simulate the complex operation of the PacifiCorp sys- tem and its integration within the Western Interconnection. The models anow for a rigorous test- ing of a reasonably broad range of commercially feasible resource alternatives available to PacifiCorp on a consistent and comparable basis. The analytical process, including the risk and uncertainty analysis, fully complies with IRP Standards and Guidelines, and is described at a high level in Chapter 2 and in greater detail in Chapter 6. The IRP analysis is designed to define a resource plan that is least cost, after consideration of risks and uncertainties. To test resource alternatives and identify a least-cost, risk adjusted plan portfolio resource options were developed and tested against each other. This testing included examination of various tradeoffs among the portfolios, such as average cost versus risk, reliabil- ity, customer rate impacts, and average annual CO2 emissions. This portfolio analysis and the results and conclusions drawn from the analysis are described in Chapter 7. Consistent with the IRP Standards and Guidelines of Oregon, Utah, and Washington, this IRP includes an Action Plan (See Chapter 8). The Action Plan details near-term actions that are nec- essary to ensure PacifiCorp continues to provide reliable and least-cost electric service after con- sidering risk and uncertainty. Appendix G provides a progress report that relates the 2007 IRP Action Plan with those provided in the 2004 IRP and 2004 IRP Update. The 2007 IRP and the related Action Plan are filed with each commission with a request for prompt acknowledgement. Acknowledgement means that a commission recognizes the IRP as meeting an regulatory requirements at the time the acknowledgement is made. In the case where a commission acknowledges the IRP in part or not at all, PacifiCorp works with the commission to modify and re-file an IRP that meets acknowledgement standards. State commission acknowledgement orders or letters typically stress that an acknowledgement does not indicate approval or endorsement of IRP conclusions or analysis results. Similarly, an acknowledgement does not imply that favorable ratemaking treatment for resources proposed in the IRP will be given. 158 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance California Subsection (i) of California Public Utilities Code, Section 454., states that utilities serving less than 500 000 customers in the state are exempt from filing an Integrated Resource Plan for Cali- fornia. PacifiCorp serves only 42 000 customers in the most northern parts of the state. Pacifi- Corp filed for and received an exemption on July 10 2003. Idaho The Idaho Public Utilities Commission s Order No. 22299, issued in January 1989, specifies integrated resource planning requirements. The Order mandates that PacifiCorp submit a Re- source Management Report (RMR) on a biennial basis. The intent of the RMR is to describe the status of IRP efforts in a concise format, and cover the following areas: Each utility's RMR should discuss any jlexibilities and analyses considered during comprehensive resource planning, such as: (1) examination of load forecast un- certainties; (2) effects of known or potential changes to existing resources; (3) consideration of demand and supply side resource options; and (4) contingencies for upgrading, optioning and acquiring resources at optimum times (considering cost, availability, lead time, reliability, risk, etc.) as future events unfold. This IRP is submitted to the Idaho PUC as the Resource Management Report for 2007, and fully addresses the above report components. The IRP also evaluates DSM using a load decrement approach, as discussed in Chapters 6 and 7. This approach is consistent with using an avoided cost approach to evaluating DSM as set forth in IPUC Order No. 21249. Oree:on This IRP is submitted to the Oregon PUC in compliance with its new planning guidelines issued in January 2007 (Order No. 07-002). These guidelines supersede previous ones, and many codify analysis requirements outlined in the Commission s acknowledgement order for PacifiCorp 2004 IRP. The Commission s new IRP guidelines consist of substantive requirements (Guideline 1), proce- dural requirements (Guideline 2), plan filing, review, and updates (Guideline 3), plan compo- nents (Guideline 4), transmission (Guideline 5), conservation (Guideline 6), demand response (Guideline 7), environmental costs (Guideline 8), direct access loads (Guideline 9), multi-state utilities (Guideline 10), reliability (Guideline 11), distributed generation (Guideline 12), and re- source acquisition (Guideline 13). Consistent with the earlier guidelines (Order 89-507), the Commission notes that acknowledgement does not guarantee favorable ratemaking treatment only that the plan seems reasonable at the time acknowledgment is given. Table 1.3 provides considerable detail on how this plan addresses each of the requirements. Utah This IRP is submitted to the Utah Public Service Commission in compliance with its 1992 Order on Standards and Guidelines for Integrated Resource Planning (Docket No. 90-2035- , " Report and Order on Standards and Guidelines ). Table 1.4 documents how PacifiCorp complies with each of these standards. 159 PacifiCorp 2007 IRP Appendix I IRP Regulatory Compliance Washin2ton This IRP is submitted to the Washington Utilities and Transportation Commission (WUTC) in compliance with its rule requiring least cost planning (Washington Administrative Code 480- 100-238), and the rule amendment issued on January 9, 2006 (WAC 480-100-238, Docket No. UE-030311). In addition to a least cost plan, the rule requires provision of a two-year action plan and a progress report that "relates the new plan to the previously filed plan. The rule amendment also now requires PacifiCorp to submit a work plan for informal commis- sion review not later than 12 months prior to the due date of the plan. The work plan is to layout the contents of the IRP, the resource assessment method, and timing anq extent of public partici- pation. PacifiCorp filed a work plan with the Commission on February 21 , 2006, and had a fol- low-up conference call with WUTC staff to make sure the work plan met staff expectations. Finally, the rule amendment now requires PacifiCorp to provide an assessment of transmission system capability and reliability. This requirement was met in this IRP by modeling the com- pany s current transmission system along with both generation and transmission resource options as part of its resource portfolio analyses. These analyses used such reliability metrics as Loss of Load Probability and Energy Not Served to assess the impacts of different resource combinations on system reliability. The stochastic simulation and risk analysis section of Chapter 7 reports the reliability analysis results. Wvomin2 On October 4, 2001 , the Public Service Commission of Wyoming issued an Order and Stipula- tion requiring PacifiCorp to file annual resource planning and transmission reports for a three- year time period beginning in 2002, each to be submitted on March 31 , Each report "win address (1) load and resource planning issues affecting Wyoming, and (2) transmission investment, op- eration and planning issues affecting Wyoming." PacifiCorp submitted its last report in March 2004. 160 Pa c i f i C o r p 20 0 7 I R P Ta b l e I . I - I n t e g r a t e d R e s o u r c e Pl a n n i n g S t a n d a r d s a n d G u i d e l i n e s S u m m a r y b y S t a t e To p i c So u r c e Fi l i n g Re q u i r e m e n t s Fr e q u e n c y Co m m i s s I O n re s p o n s e Or e ~ ( ) n Or d e r 8 9 - 50 7 Le a s t - c o s t P l a n n i n g f o r R e - so u r c e A c q u i s i t i o n s , Ap r i l 2 0 , 1 9 8 9 . Or d e r N o . 0 7 - 00 2 In v e s t i g a t i o n In t o I n t e g r a t e d R e s o u r c e P l a n - ni n g , Ja n u a r y 8 , 2 0 0 7 . Le a s t - c o s t p l a n s m u s t b e f i l e d wi t h t h e C o m m i s s i o n . Pl a n s f i l e d b i e n n i a l l y . I n t e r i m re p o r t s o n p l a n p r o g r e s s a l s o re q u i r e d ( i n f o n n a t i o n a l f i l i n g on l y ) . O r d e r 0 7 - 00 2 r e q u i r e s I R P fi l i n g w i t h i n t w o y e a r s o f i t s pr e v i o u s I R P a c k n o w l e d g e m e n t or d e r . Le a s t - c o s t p l a n ( L C P ) ac k n o w l - ed g e d if f o u n d t o c o m p l y w i t h st a n d a r d s a n d g u i d e l i n e s . A de c i s i o n m a d e i n t h e L C P p r o c - es s d o e s n o t g u a r a n t e e f a v o r a b l e ra t e - m a k i n g t r e a t m e n t . T h e OP U C m a y d i r e c t t h e u t i l i t y t o re v i s e t h e I R P o r c o n d u c t a d d i - ti o n a l a n a l y s i s b e f o r e a n a c - kn o w l e d g e m e n t o r d e r i s i s s u e d . No t e , h o w e v e r , t h a t R a t e P l a n le g i s l a t i o n a l l o w s p r e - a p p r o v a l of n e a r - te n n r e s o u r c e i n v e s t - me n t s . Ut a h Do c k e t 9 0 - 20 3 5 - St a n d a r d s a n d G u i d e l i n e s f o r In t e g r a t e d R e s o u r c e P l a n n i n g Ju n e 1 8 , 1 9 9 2 . An I n t e g r a t e d R e s o u r c e P l a n (I R P ) i s t o b e s u b m i t t e d t o Co m m i s s i o n . Fi l e b i e n n i a l l y . IR P ac k n o w l e d g e d if f o u n d t o co m p l y w i t h s t a n d a r d s a n d gu i d e l i n e s . P r u d e n c e r e v i e w s o f ne w r e s o u r c e a c q u i s i t i o n s w i l l oc c u r d u r i n g r a t e m a k i n g p r o - ce e d i n g s . W a s h i n ~ t o h WA C 4 8 0 - 10 0 - 25 1 L e a s t c o s t pl a n n i n g , M a y 1 9 , 1 9 8 7 , a n d a s am e n d e d f r o m W A C 4 8 0 - 10 0 - 23 8 Lf ! a s t C o s t P l a n n i n g R u l e - ma k i n g , Ja n u a r y 9 , 2 0 0 6 (D o c k e t # U E - 03 0 3 1 1 ) Su b m i t a l e a s t c o s t p l a n t o t h e Co m m i s s i o n . P l a n t o b e d e v e l - op e d w i t h c o n s u l t a t i o n o f C o m - mi s s i o n s t a f f , a n d w i t h p u b l i c in v o l v e m e n t . Fi l e b i e n n i a l l y . Th e p l a n w i l l b e c o n s i d e r e d , w i t h ot h e r a v a i l a b l e i n f o n n a t i o n wh e n e v a l u a t i n g t h e p e r f o n n a n c e of t h e u t i l i t y i n r a t e p r o c e e d i n g s . WU T C s e n d s a l e t t e r d i s c u s s i n g th e r e p o r t , m a k i n g s u g g e s t i o n s an d r e q u i r e m e n t s a n d a c k n o w l - ed g e s t h e r e p o r t . Ap p e n d i x 1 - I R P R e g u l a t o r y C o m p l i a n c e Id a h o Or d e r 2 2 2 9 9 El e c t r i c U t i l i t y C o n s e r v a t i o n St a n d a r d s a n d P r a c t i c e s Ja n u a r y , 1 9 8 9 . Su b m i t " Re s o u r c e M a n a g e m e n t Re p o r t " ( R M R ) o n p l a n n i n g st a t u s . A l s o f i l e p r o g r e s s r e p o r t s on c o n s e r v a t i o n a n d l o w - in c o m e pr o g r a m s . RM P t o b e f i l e d a t l e a s t b i e n n i - al l y . C o n s e r v a t i o n r e p o r t s t o b e fi l e d a n n u a l l y . Re p o r t d o e s n o t c o n s t i t u t e p r e - ap p r o v a l o f p r o p o s e d r e s o u r c e ac q u i s i t i o n s . Id a h o s e n d s a s h o r t l e t t e r s t a t i n g th a t t h e y a c c e p t t h e f i l i n g a n d ac k n o w l e d g e t h e r e p o r t a s s a t i s - fy i n g C o m m i s s i o n r e q u i r e m e n t s . 16 1 Pa c i f i C o r p 20 0 7 I R P To p i c Pr o c c s s Or e l ! o n Th c p u h l i c a n d o t h c r u t i l i t i l ' s a r c a 1 1 0 \ \ l ' d si g n i f i c a n t i m o h c m c n t in t h c p r l ' p a r a t i o n o f t h c p l a n . wi t h o p p o r t u n i t i e s t o c o n t r i b u t e an d r e c e i v e i n f o r m a t i o n . O r d e r 07 - 00 2 r e q u i r e s t h a t t h e u t i l i t y pr e s e n t I R P r e s u l t s t o t h e O P U C at a p u b l i c m e e t i n g p r i o r t o t h e de a d l i n e f o r w r i t t e n p u b l i c c o m - me n t s . C o m m i s s i o n s t a f f a n d pa r t i e s s h o u l d c o m p l e t e t h e i r co m m e n t s a n d r e c o m m e n d a t i o n s wi t h i n s i x m o n t h s a f t e r I R P fi l i n g . Fo c u s Co m p e t i t i v e s e c r e t s m u s t b e pr o t e c t e d . 20 - ye a r p l a n , w i t h e n d - e f f e c t s an d a s h o r t - te r m ( t w o - ye a r ) ac t i o n p l a n . T h e I R P p r o c e s s sh o u l d r e s u l t i n t h e s e l e c t i o n o f th a t m i x o f o p t i o n s w h i c h y i e l d s fo r s o c i e t y o v e r t h e l o n g r u n , t h e be s t c o m b i n a t i o n o f e x p e c t e d co s t s a n d v a r i a n c e o f c o s t s . El e m e n t s Ba s i c e l e m e n t s i n c l u d e : . A l l re s o u r c e s e v a l u a t e d o n a co n s i s t e n t a n d c o m p a r a b l e b a - SI S .Ri s k a n d u n c e r t a i n t y m u s t b e co n s i d e r e d . . T h e p r i m a r y g o a l m u s t le a s t c o s t , c o n s i s t e n t w i t h t h e Ut a h Pl a n n i n g p n l l ' cs s o p l . ' n t o t h c pu h l i c a l a l l s t a g c s . I R P d c \ c I - op c d i n c o n s u l t a t i o n w i t h t h e Co m m i s s i o n , i t s s t a f f , w i t h a m - pl e o p p o r t u n i t y f o r p u b l i c i n p u t . 20 - ye a r p l a n , w i t h s h o r t - te r m (f o u r - ye a r ) a c t i o n p l a n . S p e c i f i c ac t i o n s f o r t h e f i r s t t w o y e a r s a n d an t i c i p a t e d a c t i o n s i n t h e s e c o n d tw o y e a r s t o b e d e t a i l e d . T h e I R P pr o c e s s s h o u l d r e s u l t i n t h e s e - le c t i o n o f t h e o p t i m a l s e t o f re s o u r c e s g i v e n t h e e x p e c t e d co m b i n a t i o n o f c o s t s , r i s k a n d un c e r t a i n t y . IR P w i l l i n c l u d e : . R a n g e o f fo r e c a s t s o f f u t u r e lo a d g r o w t h . E v a l u a t i o n o f al l p r e s e n t a n d fu t u r e r e s o u r c e s , i n c l u d i n g de m a n d s i d e , s u p p l y s i d e a n d ma r k e t , o n a c o n s i s t e n t a n d co m p a r a b l e b a s i s . Wa s h i n ! ! t o n In c o n s u l t a t i o n \ \ i l h C o m m i s s i o n st a f f . d c w l o p a n d i m p l e m e n t a pu b l i c i n v o l v e m e n t p l a n . I n - vo l v e m e n t b y t h e p u b l i c i n d e - ve l o p m e n t o f t h e p l a n i s r e - qu i r e d . F o r t h e a m e n d e d r u l e s is s u e d i n J a n u a r y 2 0 0 6 , P a c i f i - Co r p i s r e q u i r e d t o s u b m i t a wo r k p l a n f o r i n f o r m a l c o m m i s - si o n r e v i e w n o t l a t e r t h a n 1 2 mo n t h s p r i o r t o t h e d u e d a t e o f th e p l a n . T h e w o r k p l a n i s t o l a y ou t t h e c o n t e n t s o f t h e I R P , r e - so u r c e a s s e s s m e n t m e t h o d , a n d ti m i n g a n d e x t e n t o f p u b l i c p a r - ti c i p a t i o n . 20 - ye a r p l a n , w i t h s h o r t - te r m (t w o - ye a r ) a c t i o n p l a n . Th e p l a n d e s c r i b e s m i x o f r e - so u r c e s s u f f i c i e n t t o m e e t c u r r e n t an d f u t u r e l o a d s a t " lo w e s t r e a - so n a b l e " c o s t t o u t i l i t y a n d r a t e - pa y e r s . R e s o u r c e c o s t , m a r k e t vo l a t i l i t y r i s k s , d e m a n d - s i d e re s o u r c e u n c e r t a i n t y , r e s o u r c e di s p a t c h a b i l i t y , r a t e p a y e r r i s k s po l i c y i m p a c t s , a n d e n v I r o n - me n t a l r i s k s , m u s t b e c o n s i d e r e d . Th e p l a n s h a l l i n c l u d e : . A r a n g e of f o r e c a s t s o f f u t u r e de m a n d u s i n g m e t h o d s t h a t ex a m i n e t h e e f f e c t o f e c o - no m i c f o r c e s o n t h e c o n s u m p - ti o n o f e l e c t r i c i t y a n d t h a t a d - dr e s s c h a n g e s i n t h e n u m b e r ty p e a n d e f f i c i e n c y o f e l e c t r i - Ap p e n d i x 1 - I R P R e g u l a t o r y C o m p l i a n c e Id a h o . . Ut i l i t i e s t o w o r k w i t h C o m m i s - si o n s t a f f w h e n r e v i e w i n g a n d up d a t i n g R M R s . R e g u l a r p u b l i c wo r k s h o p s s h o u l d b e p a r t o f pr o c e s s . 20 - ye a r p l a n t o m e e t l o a d o b l i g a - ti o n s a t l e a s t - c o s t , w i t h e q u a l co n s i d e r a t i o n t o d e m a n d s i d e re s o u r c e s . P l a n t o a d d r e s s r i s k s an d u n c e r t a i n t i e s . E m p h a s i s o n cl a r i t y , u n d e r s t a n d a b i l i t y , r e - so u r c e c a p a b i l i t i e s a n d p l a n n i n g fl e x i b i l i t y . Di s c u s s a n a l y s e s c o n s i d e r e d in c l u d i n g : Lo a d f o r e c a s t u n c e r t a i n t i e s ; Kn o w n o r p o t e n t i a l c h a n g e s to e x i s t i n g r e s o u r c e s ; Eq u a l c o n s i d e r a t i o n o f d e - ma n d a n d s u p p l y s i d e r e - so u r c e o p t i o n s ; 16 2 Pa c i f i C o r p 20 0 7 I R P Or e o n lo n g - r u n p u b l i c i n t e r e s t . . T h e p l a n m u s t be c o n s i s t e n t wi t h O r e g o n a n d f e d e r a l e n - er g y p o l i c y . . E x t e r n a l co s t s m u s t b e c o n - si d e r e d , a n d q u a n t i f i e d w h e r e po s s i b l e . O P U C s p e c i f i e s e n - vi r o n m e n t a l a d d e r s ( O r d e r No . 9 3 - 69 5 , D o c k e t U M 4 2 4 ) . Id e n t i f y a c q u i s i t i o n s t r a t e g i e s fo r a c t i o n p l a n r e s o u r c e s , a s - se s s a d v a n t a g e s / d i s a d v a n t a g e s of r e s o u r c e o w n e r s h i p v e r s u s pu r c h a s e s , a n d i d e n t i f y be n c h m a r k r e s o u r c e s c o n s i d - er e d f o r c o m p e t i t i v e b i d d i n g . Mu l t i - s t a t e u t i l i t i e s s h o u l d pl a n t h e i r g e n e r a t i o n a n d tr a n s m i s s i o n s y s t e m s o n a n in t e g r a t e d - s y s t e m b a s i s . . A v o i d e d co s t f i l i n g r e q u i r e d wi t h i n 3 0 d a y s o f a c k n o w l - ed g e m e n t . Ut a h . A n a l y s i s o f t h e ro l e o f c o m - pe t i t i v e b i d d i n g . A p l a n f o r a d a p t i n g to d i f f e r - en t p a t h s a s t h e f u t u r e u n f o l d s . . A c o s t ef f e c t i v e n e s s m e t h o d - ol o g y . . A n ev a l u a t i o n o f t h e f i n a n c i a l co m p e t i t i v e , r e l i a b i l i t y a n d op e r a t i o n a l r i s k s a s s o c i a t e d wi t h r e s o u r c e o p t i o n s , a n d ho w t h e a c t i o n p l a n a d d r e s s e s th e s e r i s k s . . D e f i n i t i o n o f ho w r i s k s a r e al l o c a t e d b e t w e e n r a t e p a y e r s an d s h a r e h o l d e r s DS M a n d s u p p l y s i d e r e - so u r c e s e v a l u a t e d a t " To t a l Re s o u r c e C o s t " r a t h e r t h a n ut i l i t y c o s t . Ap p e n d i x 1 - I R P R e g u l a t o r y C o m p l i a n c e Wa s h i n . to n ca l e n d - u s e s . . A n as s e s s m e n t o f c o m m e r - ci a l l y a v a i l a b l e c o n s e r v a t i o n in c l u d i n g l o a d m a n a g e m e n t as w e l l a s a n a s s e s s m e n t o f cu r r e n t l y e m p l o y e d a n d n e w po l i c i e s a n d p r o g r a m s n e e d e d to o b t a i n t h e c o n s e r v a t i o n i m - pr o v e m e n t s . . A s s e s s m e n t o f a w i d e r a n g e o f co n v e n t i o n a l a n d c o m m e r - ci a l l y a v a i l a b l e n o n c o n v e n - ti o n a l g e n e r a t i n g t e c h n o l o g i e s . A n as s e s s m e n t o f t r a n s m i s - si o n s y s t e m c a p a b i l i t y a n d r e - li a b i l i t y ( A d d e d p e r a m e n d e d ru l e s i s s u e d i n J a n u a r y 2 0 0 6 ) . . A c o m p a r a t i v e ev a l u a t i o n o f en e r g y s u p p l y r e s o u r c e s ( i n - cl u d i n g t r a n s m i s s i o n a n d d i s - tr i b u t i o n ) a n d i m p r o v e m e n t s in c o n s e r v a t i o n u s i n g " lo w e s t re a s o n a b l e c o s t " c r i t e r i a . In t e g r a t i o n o f t h e d e m a n d fo r e c a s t s a n d r e s o u r c e e v a l u a - ti o n s i n t o a l o n g - r a n g e ( a t le a s t 1 0 y e a r s ) p l a n . . A l l p l a n s sh a l l a l s o i n c l u d e a pr o g r e s s r e p o r t t h a t r e l a t e s t h e ne w p l a n t o t h e p r e v i o u s l y fi l e d I a n . Id a h o Co n t i n g e n c i e s f o r u p g r a d - in g , o p t i o n i n g a n d a c q u i r i n g re s o u r c e s a t o p t i m u m t i m e s ; Re p o r t o n e x i s t i n g r e s o u r c e st a c k , l o a d f o r e c a s t a n d a d - di t i o n a l r e s o u r c e m e n u . 16 3 PacifiCorp 2007 IRP Appendix I IRP Regulatory Compliance Table 1.2 - Handling of 2004 IRP Acknowledgement and Other IRP Requirements IRPRe.quiremenfor Recommendation Staff recommends that PacifiCorp con- tinue to evaluate and investigate IGCC in its next IRP. (Acceptance of Filing, Case No. PAC-05-, p. 6) As we indicated in our acceptance of the Company s 2003 Electric IRP fil- ing, in addition to being apprised through periodic status reports of sup- ply resources the Company is actually building or contracting for and demand side programs the Company is imple- menting, the Commission expects to receive periodic updates as to the Com- pany s specific plans for issuing re- quests for proposals (RFPs). (Accep- tance of Filing, Case No. PAC-05- Use decrement values to assess cost- effective bids in DSM RFP(s). Acquire the base DSM (PacifiCorp and ETO combined) of250 MWa and 200 MWa or more of additional Class 2 DSM found cost-effective through RFP or in- house programs, up to the levels re- quired to serve load growth, and as ap- proved by each State s Commission. (Action Item 1 revision, OPUC Order 06-029, p. 60) Execute an agreement with the Energy Trust of Oregon, as soon as possible, to reserve funds for the above-market costs of renewable resources that bene- fit Oregon ratepayers and enable timely completion of resource agreements with the recent extension of the federal production tax credit. (Additional Ac- tion Item, OPUC Order 06-029, P. 60 I:lowth€1Requirementor R,e~OInmendation , . " is Addressedintbe2007IRP PacifiCorp incorporated various IGCC re- sources, distinguished by location and tech- nology configuration (including CO2 capture and sequestration), in its capacity expansion optimization and stochastic modeling studies. Chapter 7 describes the IGCC modeling re- sults. PacifiCorp provided the Idaho Public Utility Commission procurement updates on April 12 and August 30 2006, and plans to provide them on a quarterly basis. See the "Class 2 Demand-side Management Decrement Analysis" section in Chapter 7 for updated decrement values. See the "Existing Resources" section of Chapter 4 for an update on the progress of Class 2 DSM programs, as well as Appendix , " Action Plan Status A master agreement to fund the above-market costs of new renewable energy resources was signed on April 6, 2006. 164 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance IR.PRequiremenf.or . . Recommendation' F or the next IRP or Action Plan, de- velop supply curves for various types of Class 1 DSM resources, model them as portfolio options that compete with supply-side options, and analyze cost and risk reduction benefits. Evaluate this approach for Class 2 DSM re- sources and recommend whether this approach is preferable to the current decrement approach. (Additional Ac- tion Item, OPUC Order 06-029, p. 60) For the next IRP or Action Plan, as- sume existing interruptible contracts continue unless they are not renegoti- able or other resources would provide better value. (Additional Action Item OPUC Order 06-029 . 60) F or the next IRP or Action Plan, assess IGCC technology in a location poten- tial1y suitable for CO2 sequestration including cost, commercialization status, technology risk, and compara- tive performance under future uncer- tainties, including market prices and CO2 regulation. (Additional Action Item, OPUC Order 06-029, p. 61) For the next IRP or Action Plan, ana- lyze the costs and risks of portfolios that include various combinations of additional transmission to reach re- sources that are shorter term or lower cost, along with new generating re- sources and their associated transmis- sion. (Additional Action Item, OPUC Order 06-029, p. 61) ' Howth~.Jlequir~m~~tor R coml#ejjdati9.ll isAddressedllithe.2007IRP" " PacifiCorp used Class 1 DSM proxy supply curves, developed by Quantec LLC, for port- folio optimization modeling using the Capac- ity Expansion Module. See Appendix B for the complete Quantec DSM study. Chapter 5 outlines the supply curves used in the CEM. F or Class 2 DSM, the company chose to con- tinue using the decrement approach for the 2007 IRP, but enhanced it by adopting sto- chastic simulation to capture risk. Pacifi- Corp s plan to use decrement analysis was presented and discussed at the February 10 2006 technical workshop on demand-side mana ement. PacifiCorp adopted the assumption that exist- ing interruptible contracts are extended until beyond the end of the 20-year IRP study pe- riod. PacifiCorp included several IGCC plant con- figurations and locations as resource options in its "alternative future" scenario modeling, including one with carbon capture and se- questration. IGCC resources were also in- cluded in risk analysis portfolios for stochas- tic simulation. See "Resource Options" in Chapter 5 for IGCC cost and performance characteristics. See Chapter 7 for IGCC mod- elin results. PacifiCorp included various transmission re- sources in its capacity optimization model. For a CEM sensitivity study, the company included a proxy resource representing the Frontier Line project, reflecting a strategy to access markets in California and the south- west u.s. See "Resource Expansion Alterna- tives" in Chapter 5 for details on the trans- mission resources modeled, and Chapter 7 for modelin results. 165 PacifiCorp 2007 IRP State IR~;Jl~qt!irement()r ' . . " Recommendation ' Conduct an economic analysis of achievable Class 1 and Class 2 DSM measures in PacifiCorp s service area over the IRP study period, and assess how the Company s base and planned programs compare with the cost- effective amounts determined in the study. (New IRP requirement, OPUC Order 06-029, p. 61) Determine the expected load reductions from Class 3 DSM programs such as new interruptible contracts and the En- ergy Exchange at various prices, and model these programs as portfolio op- tions that compete with supply-side op- tions. (New IRP requirement, OPUC Order 06-029 , . 61) Evaluate loss of load probability, ex- pected unserved energy, and worst-case unserved energy, as well as Class 3 DSM alternatives for meeting unserved energy. (New IRP requirement, OPUC Order 06-029, p. 61) Evaluate alternatives for determining the expected annual peak demand for determining the planning margin for example, planning to the average of the eight-hour super-peak period. (New IRP requirement, OPUC Order 06-029 Evaluate, within portfolio modeling, the potential for reducing costs and ri~ks of generation and transmission by including high-efficiency CHP re- sources and aggregated dispatchable customer standby generation of various sizes within load-growth areas. (New IRP requirement, OPUC Order 06-029 Appendix I IRP Regulatory Compliance H() wth!cR,equirem el1to rRecom In en~ at~o n . . is:A.ddressedin the2007IRP . . Due to the timing ofOPUC's 2004 acknowl- edgment Order (in January 2006), and as agreed to by OPUC staff, this requirement is being met via the MEHC commitment to per- form a multi-state DSM potentials study to be completed by June 2007. Development and use of Quantec' s proxy DSM supply curves was intended as a compromise strategy until the DSM potentials study becomes available for use in the next IRP. PacifiCorp incorporated supply curves into its portfolio modeling for the following Class 3 DSM resources: Curtailable Rates, Demand Buyback, and Critical Peak Pricing. See Chapter 4 and Appendix B for details. PacifiCorp included these supply reliability metrics as part of its stochastic portfolio risk analysis. The Planning and Risk Module (PaR) 12-percent capacity reserve margin sensitivity study included the maximum available amount of Class 3 DSM as indi- cated b the Quantec rox su ly curves. . This requirement was met via a Capacity Ex- pansion Module sensitivity analysis. See Chapter 7 for a results summary. CHP and aggregated dispatchable customer standby generation were modeled as part of a 12% planning reserve margin sensitivity analysis using PaR. See Chapter 7 for a re- sults summary. 166 PacifiCorp 2007 IRP . State ilRPRequirementor Recommendation Evaluate the potential value of CHP re- sources in deferring a major distribu- tion system investment associated with load growth, assuming physical assur- ance of load shedding when the genera- tor goes off line, up to the number of hours required to defer the investment. (New IRP requirement, OPUC Order 06-029 , . 61) If pumped storage technology becomes a viable resource option in the future the Commission expects PacifiCorp to analyze the associated environmental costs that ratepayers might incur. (OPUC Order 06-029 . 53) Analyze planning margin cost-risk tradeoffs within stochastic modeling of portfolios. If feasible, analyze the cost- risk tradeoff of all portfolios at various planning margins. If not feasible, build an portfolios to a set planning margin test them stochasticany, and adjust top- performing portfolios to higher and lower planning margins for further sto- chastic evaluation. (New requirement OPUC Order 06-029 , . For the next IRP or Action Plan, ana- lyze renewable resources in a manner comparable to other supply-side op- tions, including testing cost and risk metrics for portfolios with amounts higher and lower than current targets further refine wind's capacity contribu- tion, and consider the effect of fuel type for thermal resource additions on the Company s cost to integrate wind re- sources. (Additional Action Item OPUC Order 06-029 . 60 We also expect the Company to funy explore whether delaying a commitment to coal until IGCC technology is further commercialized is a reasonable course of action. (OPUC Order 06-029, p. 51) Appendix I IRP Regulatory Compliance Ho~ ~.t~e R~qiIir~.rtl en.~:'~*c RecolDllienda ti() n ' : .u . . is:AddJ'es's~dintb~20071IRP PacifiCorp conducted a study of distribution system investment deferral potential assum- ing a 5-megawatt CHP interconnection pro- ject in the company s west control area. See Appendix H. Pumped storage was not evaluated in this IRP due to an expected commercial operations date beyond the 10-year acquisition horizon. PacifiCorp s approach to meeting this re- quirement was to use the CEM to derive op- timal portfolios using planning reserve mar- gins set at 12%, 15%, and 18%. To determine the stochastic impacts, these same portfolios were run with the PaR model in stochastic mode. PacifiCorp also simulated risk analysis portfolios derived from CEM runs con- strained with both 12% and 15% planning reserve margIns. Proxy wind projects were included as re- source options in CEM runs , and included in stochastic simulations for evaluating risk analysis portfolios. See Appendix J for the results ofPacifiCorp s updated studies on wind integration costs, determination of cost- effective wind resources, and wind capacity planning contribution. Appendix J also in- cludes a discussion on the effect of fuel type on wind integration costs. Chapter 7 outlines stochastic simulation results for portfolios with incremental wind additions. PacifiCorp developed and evaluated a portfo- lio that excludes pulverized coal as a resource option. PacifiCorp also evaluated two addi- tional portfolios that were specified by OPUC staff. These two portfolios, each developed accordin to 12% and 15% lannin reserve 167 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance . ~' ~equirceIDenti()r" . . Recommendation We direct the Company to structure the public input process to allow sufficient time for discussion of issues raised by parties and to address relevant issues raised in this IRP. (Utah PSC, Docket No. 05-2035-, p. 21) We believe a comprehensive annual update to the IRP between the biennial IRP filings should continue. (Utah PSC, Docket No. 05-2035- , . We find reasonable the Division s re- quest for semi-annual updates of the load and resource balance. (Utah PSC Docket No. 05-2035- , . We direct the Company to investigate improving the transparency of the IRP modeling to increase confidence in the results. (Utah PSC, Docket No. 05- 2035-, p. 21) Include a section that specifically ad- dresses the PURP A Fuel Sources Stan- dard in all future Integrated Resource Plans. ("Determination Concerning The PURPA Fuel Sources Standard" Docket No. 06-999-03) Per agreement with Utah Commission staff, include a 20-year forecasted aver- age heat rate trend for the company fossil fuel generator fleet that includes IRP resources and currently planned retirements. H9wtheiR.equir~J1lent Or R.efOlJ.1m~~~ayop ' ' isAddresseClinthe'2007IRP. ,;, margins respectively, (1) defer pulverized coal until after 2014, (2), include an IGCC plant in 2014, and (3) include 600 MW of additional wind. The portfolio evaluation re- sults are summarized in Cha ter 7. PacifiCorp organized the public meeting schedule to front-load discussions on key modeling approaches and issues (DSM, re- newables, CO2 analysis, etc.). The company also distributed papers on sc.enario analysis and risk analysis portfolio development to provide interim information prior to public meetings. See Chapter 2 , " Stakeholder En- a ement" PacifiCorp will continue with biennial IRP updates, since this is now a requirement un- der the new Oregon PUC. PacifiCorp provided a semi-annual update of its load and resource balance at the April 20 2007 IRP public meeting. PacifiCorp provided stakeholders with a de- tailed modeling plan and scenario/risk analy- sis methodology, and solicited comments on them prior to the start of IRP modeling. Model results documentation has been dis- tributed at the conclusion of the key portfolio analysis milestones-evaluation of CEM runs, selection of risk analysis portfolios for stochastic simulation, and selection of the referred ortfolio. A section on fuel source diversity is included in Chapter 8 , " Action Plan A section titled , " Forecasted Heat Rate Trend " is included in Chapter 7. 168 PacifiCorp 2007 IRP IRPRequireIrient:or . . Recommendation The recommended reserve margin is greatly influenced by the nature, mix and capacity of available resources, and risks associated with any particular re- source. Thus, the company should quantify the reserve margin in a way that incorporates risks posed by each specific resource. (WUTC IRP Ac- knowledgment Letter, Docket UE- 050095, p. 10) The Commission expects PacifiCorp ' s next plan to further refine wind en- ergy s reserve value and effects on the stability of power systems. PacifiCorp should also work to minimize any qualifications around its estimates of the value of wind. The Commission en- courages PacifiCorp to continue to ex- plore renewable resources, and to de- velop these resources when economic and compatible with system objectives. (WUTC IRP Acknowledgment Letter Docket UE-050095 . 7) We encourage PacifiCorp to further re- fine its approach by developing load curves for its west-side control area. The company should explicitly look at the load shapes for residential heating and lighting to assess the potential for DSM and energy efficiency measures in Washington. (WUTC IRP Acknowl- edgment Letter, Docket UE-050095 , p. In the Commission s letter regarding PacifiCorp s 2002 IRP, the company needs to explore ways to quantify the risk preferences of customers and shareholders. Only by understanding its risks and the risk preferences of stakeholders can PacifiCorp rank and prioritize alternative resource portfo- lios. (WUTC IRP Acknowled ment Appendix 1- IRP Regulatory Compliance H()wt~~?Req ll~remen torR..~co IIlm enda OO:.D . .' . ' . is Addressed in the:!200TTRP . PacifiCorp outlined at IRP public meetings (January 13 and May 10 2006) an innovative statistical approach for determining the amount of an additional resource needed to a keep a utility system s Loss of Load Probabil- ity (LOLP) constant. This method, which ac- counts for resource-specific reliability char- acteristics, was applied in this IRP to deter- mine the Peak Load Carrying Capability for wind resources. PacifiCorp is evaluating this approach for applicability to an resource ad- ditions modeled in the IRP. See Appendix J for the results ofPacifiCorp updated studies on wind integration costs determination of cost-effective wind re- sources, and wind capacity planning contri- bution. Chapter 7 outlines stochastic simula- tion results for risk analysis portfolios with different amounts and timing of wind re- sources.PacifiCorp s preferred portfolio in- cludes 2 000 megawatts of renewables, as opposed to 1 400 megawatts for the original MEHC renewables commitment. PacifiCorp evaluated its load shapes for Class 2 DSM decrement calculation, and deter- mined that residential lighting load shapes for the west and east control areas should be added. These load shapes are reported in Chapter 5. Decrement results for the new load shapes are reported in Chapter 7 , " Class 2 DSM Decrement Analysis PacifiCorp has relied on the public process (including the 2004 IRP stakeholder satisfac- tion survey conducted in 2005) to solicit cus- tomer and other stakeholder views on what risk factors to consider and how to address them in resource portfolio evaluation. Pacifi- Corp s uncertainty and risk analysis frame- work for the 2007 IRP reflects this input. For exam Ie, the com an used risk metrics and 169 PacifiCorp 2007 IRP IRPR~qllirementor Recommendation Letter, Docket UE-050095, p. 7) The company should consider the costs and advantages of implementing a multi-objective function optimization (model) as part of its next plan. (WUTC IRP Acknowledgment Letter Docket UE-050095 , p. 8) The company needs to develop avoided costs for general purpose energy and capacity in both the short and long- term. Furthermore, PacifiCorp should derive an avoided cost schedule for transmission and distribution resources. (WUTC IRP Acknowledgment Letter Docket UE-050095 . 8 PacifiCorp s plan does not directly con- sider the price influence of various en- ergy commodities upon on another. PacifiCorp should consider whether its plan would benefit from linking gas coal and oil prices through a high-level market fundamentals tool. (WUTC IRP Acknowledgment Letter, Docket UE- 050095 . 8 The Commission encourages Pacifi- Corp to investigate using the most up- to-date models and tools, including, for example, those commonly used by other utilities such as the AURORA production cost and dispatch model. Also, additional detail regarding the al- gorithms and mathematics of the mod- eling tools would improve the value of the report. (WUTC IRP Acknowledg- ment Letter, Docket UE-050095, p. 4) Appendix 1- IRP Regulatory Compliance Ho~the quir~~~p.t'~r R~~6Iij~~I1~~t'oI1 'is,AddressedZllitbeZOO7'IRP" " . ' risk trade-off analysis to address such criteria as overa11 portfolio cost, supply reliability, and rate volatili im act, amon others. PacifiCorp and WUTC staff participated in a conference call on April 18, 2006, pertaining to this issue and others identified in the WUTC IRP acknowledgment letter. Pacifi- Corp indicated that it was not aware of a commercia11y available multi-objective opti- mization modeling tool suitable for integrated resource tannin . PacifiCorp makes avoided cost filings after each IRP is filed. The company will consider expanding its avoided cost schedules to cover the areas identified by the WUTC. PacifiCorp and WUTC staff participated in a conference call on April 18, 2006, pertaining to this issue and others identified in the WUTC IRP acknowledgment letter. The company stated that its fundamentals model- ing tool, MIDAS, addresses energy commod- ity interactions. This topic is addressed in Appendix A in the discussion on commodity nces. PacifiCorp routinely evaluates other com- puter models for applicability to the IRP process, including AURORA and its com- petitor products. PacifiCorp conducted an IRP benchmarking study in 2005 in which electric utility use of computer models was investigated. This study was included as Ap- pendix C of the 2004 IRP Update. Regarding the recommendation to disclose additional details on model algorithms and mathematics in the IRP, the company notes that its modeling tools are covered under vendor license agreements that prohibit dis- tribution of proprietary material except when re uired under re lato commission order. 170 PacifiCorp 2007 IRP ' IRP ReqiiiF~meq~jo.r; . .. Recomme.lldati(u1:. " . ' The Company used the MIDAS model to compute variations off the base fore- cast. The plan did not document the assumptions, model structure or reli- ability ofPIRA or MIDAS forecasts. PacifiCorp needs to allow access to the models used to forecast prices to Commission staff. Without knowledge of how the models operate staff cannot evaluate the fundamentals forecast model used by PIRA or other agencies. The Commission notes that other utili- ties in our jurisdiction provide staff ac- cess to representatives of the gas supply and price consultants to discuss the me- chanics of studies, data source, and pol- icy assumptions used in forecast mod- els. (WUTC IRP Acknowledgment Let- ter, Docket UE-050095 . 5) lncreasingly volatile natural gas prices have made short-term price predictions based on fundamentals modeling less reliable. Therefore, price forecasts gen- erated from non-fundamental models and the forwards market should support or supplement the price forecasts used in the two-year actions plan. (WUTC IRP Acknowledgment Letter, Docket UE-050095 , . Given the importance of individual state policies in PacifiCorp s resource acquisition decisions, the Commission specificany requests that the Company model and evaluate the effects of state specific policies on its decisions to ac- quire certain resources. (WUTC IRP Acknowledgment Letter, Docket UE- 050095, p. 10) Appendix I IRP Regulatory Compliance . . :Etowthelt.equir~p1elltor.Rec()mmendation. " ' . . isiL\:ddr~ssedJ.Iltbe2007IRP PacifiCorp proposes to institute a series of technical workshops on fundamentals model- ing for the next IRP, similar to the load fore- casting workshops held for the 2004 and 2007 IRPs. PacifiCorp will work with Commission staff to provide knowledge of PacifiCorp models and associated data and access to the company s consultants and studies upon re- quest and under appropriate confidentiality conditions where necessary. PacifiCorp and WUTC staff participated in a conference can on April 18, 2006, pertaining to this issue and others identified in the WUTC IRP acknowledgment letter. Pacifi- Corp noted that it uses market information for the first six years of forward gas prices. PacifiCorp and WUTC staff participated in a conference can on April 18 , 2006, pertaining to this issue and others identified in the WUTC IRP acknowledgment letter. The Commission s concern was focused on state economic development policies in other states. PacifiCorp agreed to address this issue in narrative fashion given that state economic development initiatives would impact the load forecast and not resource modeling di- rectly. See the load forecasting section enti- tled , " Treatment of State Economic Devel- 0 ment Policies" in A endix A. 171 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance Table 1.3 - Oregon Public Utility Commission IRP Standard and Guidelines Guideline 1; Substantive Requirements An resources must be evaluated on a con- sistent and comparable basis: An known resources for meeting the util- ity's load should be considered, including supply-side options which focus on the generation, purchase and transmission of power - or gas purchases, transportation and storage - and demand-side options which focus on conservation and demand response. a.2 An resources must be evaluated on a con- sistent and comparable basis: Utilities should compare different resource . .. . H()~)t~eGuidelilie is Addressed in the . '. '. ' 2007JRP ' PacifiCorp considered a wide range of re- sources including renewables, cogeneration (combined heat and power), power pur- chases, thermal resources, and transmission. Chapters 5 and 6 document how PacifiCorp developed and assessed these technologies. In brief, the company used a combination of PacifiCorp generation staff expertise, Elec- tric Power Research Institute Technical As- sessment Guide (TAGCID) data, and capacity expansion optimization modeling to assess these technologies. Generation resource types were initially assessed by PacifiCorp generation experts, and a list that captures the salient technology types and configura- tions was assembled (Chapter 5, Tables 5. and 5.2). Decisions on what generation re- sources to include in the Capacity Expansion Module was based on generation staff rec- ommendations and the need to limit resource options to a manageable number based on model constraints and run-time considera- tions. (The company notes that the need to place restrictions on the number of resource options is a common IRP problem for utili- ties that use such optimization models for long-term planning. Based on the modeling lessons learned for this IRP and the anticipated expansion of resource options arising from the DSM po- tentials study due in June 2007, PacifiCorp intends to explore new resource screening methods to accommodate a broader range of technologies while meeting the requirement to assess technologies on a 'consistent and comparable basis. PacifiCorp considered various combinations of fuel types, technologies, lead times, in- service dates, durations, and locations for 172 PacifiCorp 2007 IRP Appendix I IRP Regulatory Compliance 1.a.4 Lb. 1 1.b.2 fuel types, technologies, lead times, in- service dates, durations and locations in portfolio risk modeling. All resources must be evaluated on a con- sistent and comparable basis: Consistent assumptions and methods should be used for evaluation of an re- sources. All resources must be evaluated on a con- sistent and comparable basis: The after-tax marginal weighted-average cost of capital (W ACC) should be used to discount all future resource costs. Risk and uncertainty must be considered: At a minimum, utilities should address the following sources of risk and uncertainty: 1. Electric utilities: load requirements hydroelectric generation, plant forced out- ages, fuel prices, electricity prices, and costs to comply with any regulation of greenhouse gas emissions. Risk and uncertainty must be considered: Utilities should identify in their plans any additional sources of risk and uncertainty. How tI'1eGuideUne is Addressed.jllth~c . .2007':IRP . both capacity expansion optimization model- ing (deterministic risk modeling via scenario analysis) as wen as stochastic risk modeling. Chapters 6 and 7 document the modeling methodology and results, respectively. Chapter 5 describes resource attributes in detail. The range of resource attributes ac- counted for in stochastic risk analysis is in- dicated in Chapter 7, Tables 7.17 and 7. through 7.35. These tables list the resources included in the risk analysis portfolios. PacifiCorp funy complies with this require- ment. The company used the Electric Power Research Institute s Technical Assessment Guide (T AGCID) to develop generic supply- side resource attributes based on a consistent characterization methodology. For demand- side resources, the company used Quantec LLC's proxy supply curves, which applied a consistent methodology for determining technical, market, and achievable DSM po- tential. An portfolio resources were evalu- ated using the same sets of inputs. These inputs are documented in Appendix A. PacifiCorp applied its after-tax W ACC 1 percent to discount an cost streams. PacifiCorp funy complies with this require- ment. Each of the sources of risk identified in this guideline is treated as a stochastic variable in Monte Carlo production cost simulation. See the stochastic modeling methodology section in Chapter 7. PacifiCorp evaluated additional risks and uncertainties, including resource capital costs, coal prices, and the level of DSM achievable potential. See Chapter 6 for a discussion on what variables were modeled for scenario and stochastic risk analysis. 173 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance 1.c. Requirement The primary goal must be the selection of a portfolio of resources with the best com- bination of expected costs and associated risks and uncertainties for the utility and its customers ("best cost/risk portfolio The planning horizon for analyzing re- source choices should be at least 20 years and account for end effects. Utilities should consider all costs with a reasonable likelihood of being included in rates over the long term, which extends beyond the planning horizon and the life of the re- source. Utilities should use present value ofreve- nue requirement (PVRR) as the key cost metric. The plan should include analysis of current and estimated future costs for all long-lived resources such as power plants, gas storage facilities, and pipelines as weB as aU short-lived resources such as gas supply and short-term power pur- chases. To address risk, the plan should include, at a mllllmum: I. Two measures of PVRR risk: one that measures the variability of costs and one that measures the severity of bad out- comes. To address risk, the plan should include, at a mllllmum: 2. Discussion of the proposed use and im- pact on costs and risks of physical and financial hedging. The utility should explain in its plan how its resource choices appropriately balance cost and risk. . he't;;uideli~edsi\.ddr.~ssedin.the . ' ' 2007:IRP. " PacifiCorp evaluated cost/risk tradeoffs for each of the risk analysis portfolios consid- ered. See Chapter 7 for the company s port- folio risk analysis and determination of the preferred portfolio. PacifiCorp used a 20-year study period for portfolio modeling, and a real levelized revenue requirement methodology for treat- ment of end effects. PacifiCorp fuUy complies. Chapter 6 pro- vides a description ofthe PVRR methodol- ogy. PacifiCorp uses the standard deviation of stochastic production costs as the measure of cost variability. For the severity of bad out- comes, the company calculates several measures, including stochastic upper-tail PVRR (mean of highest five Monte Carlo iterations), risk exposure (upper-tail mean PVRR minus overaU mean PVRR), and 95th percentile stochastic PVRR. A discussion on costs and risks of physical and financial hedging is provided in Chapter Chapter 7 summarizes the results of Pacifi- Corp s cost/risk tradeoff analysis, and de- scribes what criteria the company used to determine what resource combinations pro- vide an appropriate balance between cost and risk. 174 PacifiCorp 2007 IRP 1.d The plan must be consistent with the long- run public interest as expressed in Oregon and federal energy policies. Appendix I IRP Regulatory Compliance HowtheGuideline is .Addressedil1. the 2007.1RP . '. . PacifiCorp considered both current and ex- pected state and federal energy policies in portfolio modeling. Chapter 7 describes the decision process used to derive portfolios which includes consideration of state re- source policy directions. Guideline 2. ProceduralRequirenu~n.ts The public, which includes other utilities should be aBowed significant involvement in the preparation of the IRP. Involvement includes opportunities to contribute infor- mation and ideas, as well as to receive information. Parties must have an oppor- tunity to make relevant inquiries of the utility formulating the plan. Disputes about whether information requests are relevant or unreasonably burdensome, or whether a utility is being properly respon- sive, may be submitted to the Commission for resolution. While confidential information must be protected, the utility should make public in its plan, any non-confidential informa- tion that is relevant to its resource evalua- tion and action plan. Confidential informa- tion may be protected through use of a protective order, through aggregation or shielding of data, or through any other mechanism approved by the Commission. The utility must provide a draft IRP for public review and comment prior to filing a final plan with the Commission. Guideline 3: Plan Filing, ReView, and Updates A utility must file an IRP within two years of its previous IRP acknowledgment order. If the utility does not intend to take any significant resource action for at least two years after its next IRP is due, the utility may request an extension of its filing date from the Commission. The utility must present the results of its filed plan to the Commission at a public PacifiCorp fuBy complies with this require- ment. Chapter 2 provides an overview of the public process, while Appendix F documents the details on public meetings held for the 2007 IRP. Both IRP volumes provide non-confidential information the company used for portfolio evaluation, as weB as other data requested by stakeholders. PacifiCorp also provided stakeholders with non-confidential informa- tion to support public meeting discussions via emaiL PacifiCorp distributed a draft IRP document for external review on April 20, 2007. This Plan complies with this requirement. PacifiCorp will adhere to this guideline. 175 PacifiCorp 2007 IRP Appendix I IRP Regulatory Compliance Req11irement meeting prior to the deadline for written public comment. Commission staff and parties should com- plete their comments and recommenda- tions within six months of IRP filing. The Commission will consider comments and recommendations on a utility's plan at a public meeting before issuing an order on acknowledgment. The Commission may provide the utility an opportunity to revise the plan before issuing an acknowl- edgment order. The Commission may provide direction to a utility regarding any additional analyses or actions that the utility should undertake in its next IRP. Each utility must submit an annual update on its most recently acknowledged plan. The update is due on or before the ac- knowledgment order anniversary date. Once a utility anticipates a significant de- viation from its acknowledged IRP, it must file an update with the Commission unless the utility is within six months of filing its next IRP. The utility must sum- marize the update at a Commission public meeting. The utility may request acknowl- edgment of changes in proposed actions identified in an update. Unless the utility requests acknowledge- ment of changes in proposed actions, the annual update is an informational filing that: 1. Describes what actions the utility has taken to implement the plan; 2. Provides an assessment of what has changed since the acknowledgment order that affects the action plan, including changes in such factors as load, expiration of resource contracts, supply-side and de- mand-side resource acquisitions, resource . costs, and transmission availability; and 3. Justifies any deviations from the ac- Howt~eGuideUije;js.Addressediri tbe . " 20071RP' Not applicable Not applicable Not applicable Not applicable Not applicable 176 Appendix 1- IRP Regulatory CompliancePacifiCorp 2007 IRP How the Guideline isAddtessediu,the . 2007IRP J-" "' Requirement. knowledged action plan. Guidelitie-f.'"PlariComponellts(atarij.irtimum t1mstinclude. .. . An explanation of how the utility met each The purpose of this table is to comply with of the substantive and procedural require- this guideline. ments PacifiCorp developed low, medium, and high load growth forecasts for scenario analysis using the Capacity Expansion Mod- ule. Stochastic variability of loads was also captured in the risk analysis. See Chapter 6 for a description of the load forecast data and Chapter 7 for scenario and risk analysis results. This Plan complies with the requirement. See Chapter 4 for details on annual capacity and energy balances. Existing transmission rights are reflected in the IRP model topolo- gies, as mentioned in Appendix A (Trans- mission System). Analysis of high and low load growth sce- narios in addition to stochastic load risk analysis with an explanation of major as- sumptions For electric utilities, a determination of the levels of peaking capacity and energy ca- pability expected for each year of the plan given existing resources; identification of capacity and energy needed to bridge the gap between expected loads and resources; modeling of all existing transmission rights, as well as future transmission addi- tions associated with the resource portfo- lios tested For gas utilities only Identification and estimated costs of an supply-side and demand side resource options, taking into account anticipated advances in technology Analysis of measures the utility intends to take to provide reliable service, including cost-risk tradeoffs Not applicable Chapter 5 identifies the resources included in this IRP , and provides their detailed cost and performance attributes (see Tables 5. through 5.4). In addition to incorporating a planning re- serve margin for an portfolios evaluated, the company used several measures to evaluate relative portfolio supply reliability. These are described in Chapter 6. PacifiCorp con- ducted several sensitivity studies to deter- mine the cost/risk tradeoff of different plan- ning reserve margin levels. These studies and resulting company conclusions, are documented in Chapter 7. Appendix A and Chapter 6 describe the key assumptions and alternative scenarios used in this IRP. Identification of key assumptions about the future (e., fuel prices and environ- mental compliance costs) and alternative scenarios considered 177 PacifiCorp 2007 IRP Appendix I IRP Regulatory Compliance 4.i Construction of a representative set of resource portfolios to test various operat- ing characteristics, resource types, fuels and sources, technologies, lead times, in- service dates, durations and generalloca- tions - system-wide or delivered to a spe- cific portion of the system Evaluation of the performance of the can- didate portfolios over the range of identi- fied risks and uncertainties Results of testing and rank ordering of the portfolios by cost and risk metric, and interpretation of those results. Analysis of the uncertainties associated with each portfolio evaluated. Selection of a portfolio that represents the best combination of cost and risk for the utility and its customers. Identification and explanation of any in- consistencies of the selected portfolio with any state and federal energy policies that may affect a utility's plan and any barriers to implementation. An action plan with resource activities the utility intends to undertake over the next two to four years to acquire the identified resources, regardless of whether the activ- ity was acknowledged in a previous IRP with the key attributes of each resource specified as in portfolio testing. GuidelineS:. Transmission Portfolio analysis should include costs to the utility for the fuel transportation and electric transmission required for each resource being considered. In addition utilities should consider fuel transportation and electric transmission facilities as re- source options, taking into account their value for making additional purchases and 4.1 . . JHoW1:b.eGu~~elineis.Addresselljn: the . " 2007IRp This Plan documents the development and results for 56 portfolios evaluated in this IRP (Chapter 7). Chapter 7 presents the deterministic and stochastic portfolio modeling results, and describes portfolio attributes that explain relative differences in cost and risk perform- ance. Chapter 7 provides tables and charts with performance measure results, including rank ordering as appropriate. PacifiCorp fully complies with this guide- line. See the responses to l.l and l.b.2 above. See 1.c above. This IRP is presumed to have no inconsis- tencies. Chapter 8 presents the 2007 IRP Action Plan. PacifiCorp evaluated proxy transmission resources on a comparable basis with respect to other proxy resources in this IRP. For example , the Capacity Expansion Module was allowed to select the most economic transmission options given other supply and demand-side resource options selected by the model. Fuel transportation costs were 178 Appendix 1- IRP Regulatory CompliancePacifiCorp 2007 IRP How the Guid~lillelsA~dre~sedIllthe 200TIRP . . . factored into resource costs. .. .. '" ~eq1iirement sales, accessing less costly resources in remote locations, acquiring alternative fuel supplies, and improving reliability. Gllid eline6 :Co nserv ati 0 Each utility should ensure that a conserva- tion potential study is conducted periodi- cally for its entire service territory. To the extent that a utility controls the level of funding for const?rvation programs in its service territory, the utility should include in its action plan all best cost/risk portfolio conservation resources for meet- ing projected resource needs, specifying annual savings targets. To the extent that an outside party admin- isters conservation programs in a utility' service territory at a level of funding that is beyond the utility's control, the utility should: 1. Determine the amount of conservation resources in the best cost/risk portfolio without regard to any limits on funding of conservation programs; and 2. Identify the preferred portfolio and ac- tion plan consistent with the outside party's projection of conservation ac- quisition. Guideline 7: Demand Response Plans should evaluate demand response resources, including voluntary rate pro- grams, on par with other options for meet- ing energy, capacity, and transmission needs (for electric utilities) or gas supply and transportation needs (for natural gas utilities). Guideline 8; Environmental Costs. Utilities should include in their base-case analyses the regulatory compliance costs they expect for carbon dioxide (CO2), ni- trogen oxides, sulfur oxides, and mercury emissions. Utilities should analyze the range of potential CO2 regulatory costs in A multi-state demand-side management po- tentials study is scheduled for completion in June 2007. A discussion on the treatment of conserva- tion programs (Class 2 DSM) is included in Chapter 6 , " Oregon Public Utility Commis- sion Guidelines for Conservation Program Analysis in the IRP. See the response for 6.b above. PacifiCorp evaluated demand response re- sources (Class 3 DSM) on a consistent basis with other resources in its CEM alternative future scenario analysis, as well as con- ducted a sensitivity analysis using the Plan- ning and Risk Module. See Chapter 7. This IRP fuBy complies with the CO2 com- pliance cost analysis requirements in Order No. 93-695. Modeling results for the CO2 cost adder levels are reported in Chapter 7. 179 PacifiCorp 2007 IRP Appendix I IRP Regulatory Compliance.. No. . Requirement Order No. 93-695 , from zero to $40 (1990$). In addition, utilities should per- form sensitivity analysis on a range of reasonably possible cost adders for nitro- gen oxides, sulfur oxides, and mercury, if applicable. Guidelille9: DirectAccessLoads An electric utility's load-resource balance should exclude customer loads that are effectively committed to service by an alternative electricity supplier. - . Guideline! 0: - Multi..state-Htilith~s.i '10 Multi-state utilities should plan their gen- eration and transmission systems, or gas supply and delivery, on an integrated sys- tem basis that achieves a best cost/risk portfolio for all their retail customers. Guidelinell :.ReWibility11 Electric utilities should analyze reliability within the risk modeling of the actual port- folios being considered. Loss of load probability, expected planning reserve margin, and expected and worst-case un- served energy should be determined by year for top-performing portfolios. Natural gas utilities should analyze, on an inte- grated basis, gas supply, transportation and storage, along with demand-side re- sources, to reliably meet peak, swing, and base-load system requirements. Electric and natural gas utility plans should dem- onstrate that the utility's chosen portfolio achieves its stated reliability, cost and risk objectives. Guideline 12: Distributed Generation12 Electric utilities should evaluate distrib- uted generation technologies on par with other supply-side resources and should consider, and quantify where possible, the additional benefits of distributed genera- tion. Guideline 13: ,- Resource Acquisition . How the Guideline is AddressedJn the' 2007IRP' PacifiCorp continues to plan for load for direct access customers. The 2007 IRP conforms to the multi-state planning approach as stated in Chapter 2. PacifiCorp fully complies with this guide- line. See the response to 1.c.l above. Chapter 8 describes the role of reliability, cost, and risk measures in determining the preferred portfolio. Scatter plots of portfolio cost versus risk at different CO2 cost adder levels were used to inform the cost/risk tradeoff analysis. The preferred portfolio was also shown to meet reliability goals on the basis of average annual Energy Not Served and other reliability measures (Chap- ter 7). PacifiCorp evaluated several types of distri- bution generation, including combined heat and power and customer-owned standby generation. The results of these evaluations are documented in Chapter 8. 180 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance. . H owt~~"Gp.idelin~lsl\UdreS sed tb e. 0 .. u 2007I.Re. 0 . ' Chapter 8 outlines the procurement approach for each proxy resource type identified in the action plan. - . Requirement. . An electric utility should, in its IRP: 1. Identify its proposed acquisition strat- egy for each resource in its action plan. 2. Assess the advantages and disadvan- tages of owning a resource instead of purchasing power from another party 3. Identify any Benchmark Resources it plans to consider in competitive bidding A discussion of the advantages and disad- vantages of owning a resource instead of purchasing it is included in Chapter 8. Benchmark resources for the 2012 are cited in Chapter 3, Recent Resource Procurement Activities. Not applicableFor gas utilities onlyl3. Table I'" - Utah Public Service Commission IRP Standard and Guidelines Howthe StartdardsandGuidelines are0 .- AddressedoiIl1I1C2007"I.ReRcq uirement~o. Procedural Issues The Commission has the legal authority to promulgate Standards and Guidelines for integrated resource planning. Information Exchange is the most reason- ahle method for developing and imple- menting integrated resource planning in Utah. Prudence Reviews of new resource acqui- sitions wiB occur during ratemaking pro- ceedings. PacifiCorp s integrated resource planning process will be open to the public at an stages. The Commission, its staff, the Di- vision, the Committee, appropriate Utah state agencies, and other interested parties can participate. The Commission wiB pur- sue a more active-directive role if deemed necessary, after formal review of the plan- ning process. Consideration of environmental external- ities and attendant costs must be included in the integrated resource planning analy- Not addressed; this is a Utah Public Service Commission responsibility Information exchange has been conducted throughout the IRP process. Not addressed; ratemaking occurs outside of the IRP process PacifiCorp s public process is described in Chapter 2. A record of public meetings is provided as Appendix F. PacifiCorp used a scenario analysis approach along with externality cost adders to model environmental externality costs. See Chapter , 5 181 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance SlS. The integrated resource plan must evaluate supply-side and demand-side resources on a consistent and comparable basis. A voided Cost should be determined in a manner consistent with the Company Integrated Resource Plan. The planning standards and guidelines must meet the needs of the Utah service area, but since coordination with other jurisdictions is important, must not ignore the rules governing the planning process already in place in other jurisdictions. The Company s Strategic Business Plan must be directly related to its Integrated Resource Plan. Howthe Standards and . Guidelines. are . . Addressediuthe.2007,IRP .. 6 for a description of the methodology em- ployed. Supply, transmission, and demand-side re- sources were evaluated on a comparable basis using PacifiCorp s capacity expansion optimization model (CEM). (The one excep- tion was Class 2 DSM, due to the unavail- ability of supply curves for this IRP.) Also see the response to number 4.b.ii below. Consistent with the Utah rules, PacifiCorp determination of avoided costs will be han- dled in a manner consistent with the IRP with the caveat that the costs may be up- dated if better information becomes avail- able. This IRP was developed in consultation with parties from all state jurisdictions, and meets all formal state IRP guidelines. PacifiCorp s business plan is directly related to the IRP; the business planning process is informed by the IRP resource analysis, the action plan, and subsequent procurement activities. Due to timing and scope differ- ences, these two plans do not match in all respects. The 2007 IRP will be used to in- form the next version of the Business Plan. Standards and Guidelines Definition: Integrated resource planning is a utility planning process which evaluates all known resources on a consistent and comparable basis, in order to meet current and future customer electric energy ser- vices needs at the lowest total cost to the utility and its customers, and in a manner consistent with the long-run public inter- est. The process should result in the selec- tion of the optimal set of resources given the expected combination of costs, risk Chapter 2 discusses the planning principles used for developing this IRP, and the quali- fications surrounding the company s long term resource planning process. The com- pany notes that this definition does not spec- ify what constitutes "optimality" given re- source decision-making constrained by (1) consideration of risk, uncertainty, disparate state policy goals and stakeholder interests and (2) the complexity and limitations of the IRP modeling effort. As indicated in Chapter 182 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance a.i Requirement and uncertainty. The Company wiH submit its Integrated Resource Plan bienniany. IRP win be developed in consultation with the Commission, its staff, the Division of Public Utilities, the Committee of Con- sumer Services, appropriate Utah state agencies and interested parties. PacifiCorp will provide ample opportunity for public input and information exchange during the development of its Plan. PacifiCorp s integrated resource plans wiH include: a range of estimates or forecasts of load growth, including both capacity (kW) and energy (kWh) requirements. The forecasts wiH be made by jurisdiction and by general class and win differentiate energy and capacity requirements. The Company wiH include in its forecasts an on-system loads and those off-system loads which they have a contractual obli- gation to fulfill. Non-firm off-system sales are uncertain and should not be explicitly incorporated into the load forecast that the utility then plans to meet. However, the Plan must have some analysis of the off- system sales market to assess the impacts such markets wiH have on risks associated with different acquisition strategies. . . Howfbe:SfandardS'and,Guidelines.are . . . ' Addressedinithe:2007IRP . , PacifiCorp believes that a successful IRP attempts to derive a robust resource plan under a reasonably wide range of potential futures For this IRP, the company received a filing extension from the Utah Public Service Commission and other state commissions. This extension was necessary to realign the IRP process to address new and expected changes in state resource policy that came into play well into this IRP development cycle. PacifiCorp s public process is described in Chapter 2. A record of public meetings is provided as Appendix F. PacifiCorp implemented a load forecast range for both deterministic scenario analy- sis as wen as for stochastic short-term and long-term variability. Details concerning the load forecasts used in the 2007 IRP are pro- vided in Chapter 4 and Appendix A. Details on the forecast ranges developed for sce- nario and stochastic analysis are documented in Chapter 6 and Appendix E, respectively. Price risk associated with market sales is captured in the company s stochastic simula- tion results. Current off-system sales agree- ments are included in the IRP models. The company is not planning to enter into additional long term firm sales agreements; therefore, associated risks do not impact the selection of the preferred portfolio. For sys- tem balancing sales, PacifiCorp recognizes that transactions may be affected by new resource constraints imposed by regulators (carbon emission and renewable portfolio standards in particular). These impacts wiH 183 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance a.ii Analyses of how various economic and demographic factors, including the prices of electricity and alternative energy sources, will affect the consumption of electric energy services, and how changes in the number, type and efficiency of end- uses will affect future loads. A n evaluation of all present and future resources, including future market oppor- tunities (both demand-side and supply- side), on a consistent and comparable ba- SIS. An assessment of all technically feasible and cost-effective improvements in the efficient use of electricity, including load management and conservation. An assessment of all technically feasible generating technologies including: renew- able resources, cogeneration, power pur- chases from other sources, and the con- struction of thermal resources. . '. .. .. Howdu~Standard.sall.a~uid~lilles are . . Addressedih,the12007.tl~, ' ' be considered in future IRP resource analy- ses. Appendix A documents how demographic and price factors are used in the load fore- casting process. Appendix A also documents price elasticity studies conducted on Utah load. Resources were evaluated on a consistent and comparable basis using the Capacity Expansion Module. There were some excep- tions due to the availability of data for this IRP, such as Class 2 DSM. Chapter 6 pro- vides a discussion on how Class 2 DSM re- source potential was addressed in this IRP. PacifiCorp contracted with Quantec, LLC to assess the technical, market, and achievable potential for various dispatchable and price- responsive load control programs (Pacifi- Corp Class 1 and Class 3 DSM). The associ- ated assessment is described in Chapter 5 while Quantec s assessment report is in- cluded as Appendix B. PacifiCorp s treatment of conservation pro- grams (Class 2 DSM) is addressed in Chap- ter 6 ("Public Utility Commission Guide- lines for Conservation Program Analysis in the IRP" PacifiCorp considered a wide range of re- sources including renewables, cogeneration (combined heat and power), power pur- chases, thermal resources, and transmission. Chapters 5 and 6 document how PacifiCorp developed and assessed these technologies. In brief, the company used a combination of PacifiCorp generation staff expertise, Elec- tric Power Research Institute Technical As- sessment Guide (T AGQY) data, and capacity expansion optimization modeling to assess these technologies. Generation resource types were initially assessed by PacifiCorp 184 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance b.iii The resource assessments should include: life expectancy of the resources, the rec- ognition of whether the resource is replac- ing/adding capacity or energy, dis- patchability, lead-time requirements flexibility, efficiency of the resource and opportunities for customer participation. An analysis of the role of competitive bid- ding for demand-side and supply-side re- source acquisitions A 20-year planning horizon. An action plan outlining the specific re- source decisions intended to implement the integrated resource plan in a manner consistent with the Company s strategic business plan. The action plan will span a four-year horizon and will describe spe- lIC)wfhe. Standards and Guidelil1es are . . Addressedinthe'20Q7IRP generation experts, and a list that captures the salient technology types and configura- tions was assembled (Chapter 5, Tables 5. and 5.2). Decisions on what generation re- sources to include in the Capacity Expansion Module was based on generation staff rec- ommendations and the need to limit resource options to a manageable number based on model constraints and run-time considera- tions. (The company notes that the need to place restrictions on the number of resource options is a common IRP problem for utili- ties that use such optimization models for long-term planning. Based on the modeling lessons learned for this IRP and t~e anticipated expansion of resource options arising from the DSM po- tentials study due in June 2007, PacifiCorp intends to explore new resource screening methods to accommodate a broader range of technologies while meeting the requirement to assess technologies on a 'consistent and comparable basis. PacifiCorp captures and models these re- source attributes in its IRP models. The proxy demand curves used to represent de- mand-side management programs explicitly incorporates estimated rates of program and event participation. A description of the role of competitive bid- ding and other procurement methods is pro- vided in Chapter 8 ("IRP Resource Pro- curement Strategy This IRP uses a 20-year study horizon (2007-2026) The action plan is provided in Chapter 8. A status report of the actions outlined in the previous action plan (2004 IRP and the 2004 IRP Update) is provided as Appendix G. 185 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance ReqUirement cific actions to be taken in the first two years and outline actions anticipated in the last two years. The action plan will include a status report of the specific actions con- tained in the previous action plan. A plan of different resource acquisition paths for different economic circum- stances with a decision mechanism to se- lect among and modify these paths as the future unfolds. An evaluation of the cost-effectiveness of the resource options from the perspectives of the utility and the different classes of ratepayers. In addition, a description of how social concerns might affect cost ef- fectiveness estimates of resource options. An evaluation of the financial, competi- tive, reliability, and operational risks asso- ciated with various resource options and how the action plan addresses these risks in the context of both the Business Plan and the 20-year Integrated Resource Plan. The Company will identify who should . '. . .. .. " Howt~e Stal1d~r~saD(l~lIidelinesare . . . Addresse~d:,ili"the200,jIRP Chapter 8 includes a section that describes PacifiCorp s strategy for meeting this re- quirement. In short, the company will use its IRP models, in conjunction with scenario analysis, to evaluate resource bids submitted under its Base Load Request For Proposals issued on AprilS, 2007. PacifiCorp provides resource-specific utility and total resource cost information in Chap- ter 5 (Tables 5.2 through 5.4). The IRP document addresses the impact of social concerns on resource cost- effectiveness in the following ways: Portfolios were evaluated using CO2 adders that ranged from $0 to $61 per ton. The cost impact of renewable portfolio standards is captured in several portfolio scenario analyses (Chapter 7) PacifiCorp conducted a study to deter- mine the cost and risk impact of wide- spread adoption of a greenhouse gas emissions performance standard (Chap- ter 7) Appendix B includes a section on DSM program valuation, which covers societal value factors (for example, environ- mental and reliability benefits) Discussions on market risks by resource type are included in Chapter 5 ("Resource De- scriptions Resource capital cost uncertainty and tech- nological risk is addressed in Chapter 5 Handling of Technology Improvement 186 PacifiCorp 2007 IRP Appendix 1- IRP Regulatory Compliance 4.i Considerations permitting flexibility in the planning process so that the Company can take advantage of opportunities and can prevent the premature foreclosure of op- tions. An analysis of tradeoffs; for example, be- tween such conditions of service as reli- ability and dispatchability and the acquisi- tion of lowest cost resources. A range, rather than attempts at precise quantification, of estimated external costs which may be intangible, in order to show how explicit consideration of them might affect selection of resource options. The Company will attempt to quantify the magnitude of the externalities, for exam- ple, in terms of the amount of emissions released and dollar estimates of the costs of such externalities. A narrative describing how current rate design is consistent with the Company integrated resource planning goals and how changes in rate design might facilitate integrated resource planning objectives. PacifiCorp will submit its IRP for public comment, review and acknowledgement. 4.1 HowtheStaridards and GuideIlfies Addressed in the 2007IRP, Trends and Cost Uncertainty" For reliability risks, the stochastic simulation model incorporates stochastic volatility of forced outages for thermal plants and hydro availability. These risks are factored into the comparative evaluation of portfolios and the selection of the preferred portfolio upon which the action plan is based. Identification of the classes of risk and how these risks are allocated to ratepayers and investors is discussed in Chapter 2. PacifiCorp discusses how planning flexibil- ity came into play for the selection of the preferred portfolio (Chapter 7 , " Preferred Portfolio Selection and Justification PacifiCorp examined the trade-off between portfolio cost and risk. This trade-off analy- sis is documented in Chapter 7. A discussion on the trade-off between cost and the plan- ning reserve margin is also provided in Chapter 7 ("Planning Reserve Margin Selec- tion PacifiCorp estimated environmental exter- nality costs for CO2, NOx, SO2, and mercury with use of cost adders and assumptions regarding the form of compliance strategy (for example, cap-and-trade versus a per-ton tax for CO2). For CO2 externality costs, the company used scenarios with various cost adder levels to capture a reasonable range of cost impacts. This narrative is provided in Chapter 4 ("Ex- isting DSM Program Status PacifiCorp distributed the draft IRP docu- ment for public review and comment on April 20, 2007. This IRP report constitutes 187 PacifiCorp 2007 IRP The public, state agencies and other inter- ested parties will have the opportunity to make formal comment to the Commission on the adequacy of the Plan. The Commis- sion will review the Plan for adherence to the principles stated herein, and will judge the merit and applicability of the public comment. If the Plan needs further work the Commission will return it to the Com- pany with comments and suggestions for change. This process should lead more quickly to the Commission s acknowl- edgement of an acceptable Integrated Re- source Plan. The Company will give an oral presentation of its report to the Com- mission and all interested public parties. Formal hearings on the acknowledgement of the Integrated Resource Plan might be appropriate but are not required. Acknowledgement of an acceptable Plan will not guarantee favorable ratemaking treatment of future resource acquisitions. The Integrated Resource Plan will be used in rate cases to evaluate the performance of the utility and to review avoided cost calculations. Appendix 1- IRP Regulatory Compliance . Htrwt~ejStalia.~rd~.~ndGuiCtelines . ar . .' . :A:ddressed inthe2007:IRP . . the formal submission of the IRP for ac- knowledgement. Not addressed; this is a post-filing activity. Not addressed; this is not a PacifiCorp activ- ity. Not addressed; this refers to a post-filing activity . 188 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology APPENDIX J - WIND RESOURCE METHODOLOGY This appendix summarizes the wind resource analyses used to help characterize wind resources included in PacifiCorp s IRP models. Specifically, the appendix covers (1) the expected cost of integrating various amounts of wind generation with other portfolio resources-reflecting a re- finement and update of previous analysis conducted for PacifiCorp s integrated resource plan- ning, (2) a resource screening effort to determine a base amount of wind resources to include in portfolios subjected to stochastic production cost simulation, and (3) the calculation of capacity planning contribution of wind resources, accounting for generation variability. In addition to summarizing the results of its wind resource studies, this appendix briefly de- scribes current efforts by organizations in the Pacific Northwest to assess wind integration impli- cations. Finally, the last section of this appendix discusses the role of resource fuel type on the company s strategy for integrating wind resources. This discussion addresses an Oregon Public Utility Commission requirement to investigate this topic for the 2007 IRP. A new methodology was developed to explicitly calculate the load following reserve requirement based on the uncertainty in load for the next hour on an operational basis, which allowed Pacifi- Corp to apply the same analytical approach to estimating the incremental reserve requirements for wind. The availability of hourly wind data for resources distributed across PacifiCorp service territories over comparable historical time horizons enabled analysts to include proxy wind re- sources with realistic operating characteristics into the analysis. Further, a development in tech- niques for estimating load carrying capability allowed analysts to estimate the capacity contribu- tions of various wind combinations of wind developments that restricted interactions due to cor- related generation from nearby plants. Analysts were able to improve the characterization of wind operations and interactions with the power system in the present analysis. WIND INTEGRATION COSTS Across all analyses, wind integration costs have generally been divided into two categories - incremental reserve requirements and system balancing costs. The former is related to the need for dynamic resources to be held in reserve, able to respond on a roughly ten minute basis to rap- idly changing load/resource balance conditions. Since wind resource generation can be quite variable over time periods from about ten minutes to several hours, it will be necessary to in- crease the amount of reserves as the quantity of wind resources on the system increases. System balancing costs represent the difference in value between the energy delivered from wind re- sources compared to that delivered from less volatile resources. Consistent with previous stud- ies, PacifiCorp reviewed both categories of wind integration costs: the incremental reserve re- quirement and the system balancing cost. Incremental Reserve Requirements Operating reserves are divided into categories based on purpose and on characteristics. Naming conventions for categorizing reserves by their intended purpose are not standard in the industry. Reserves held for responding to the sudden failure of generation or transmission equipment are usually called "contingency reserves . Reserves held to respond to changes in system frequency 189 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology over a period of a few seconds will be referred to as "regulating reserves . Generation that can be brought on over a multiple-minute time period will be termed "load following reserves. Wind projects are not expected to affect the need to hold contingency reserves, as there is no significant difference between wind generation and other types of generation with respect to sudden equipment failures, or other outages. The multiplicity of individual generators within a typical wind farm inherently makes them less susceptible to losing the entire output of the farm due to generator or turbine failures (but not transmission-related outages). Wind projects are subject to relatively rapid shutdown when wind speeds reach the cutout level. However, this has not been a significant problem in practice, as individual wind turbines do not tend to shut down simultaneously. Similarly, regulating reserve requirements do not appear to be significantly affected by wind turbines . The second-by-second variations in wind project output are found to be not signifi- cantly different from other generating units and the ambient fluctuations of the load. They are also not correlated with either load fluctuations, or distant wind projects. Wind variations over periods often minutes to an hour are significant, and can cause operators to rapidly start up units on short notice within an hour. Fluctuations of the combined output of a collection of wind projects increases with the amount of total wind generation connected to the system. For the 2007 IRP, a new methodology was developed to explicitly calculate the load following reserve requirement based on the uncertainty in load for the next hour on an operational basis. Operators have estimates of the behavior of loads for the next hour and move to bring on or back off resources as necessary to accommodate the expected change. Knowing that the actual load of the next hour will likely be different than the forecast and that there will be deviations within the hour. operators hold additional resources ready to respond should they underestimate the need for resources. (Generally, overestimates are not a problem, though it is an additional concern). Reservc levels are established to ensure that the shortfall can be met a minimum percentage of the timc-general1y around 95 percent. The methodology is graphically illustrated in Figure 1.1 which shows how the load forecast changes from one hour to the next. Assuming that the range of actual outcomes for the next hour can be approximated by a normal distribution, the amount of additional reserve capability that is necessary to provide assurance of having adequate re- sourccs available at least 95 percent of the time can be calculated. This methodology can be applied first to the system load alone and then again to the system load net of wind generation. The difference between the two results is the estimated incremental re- serve requirement due to the wind resources. 4 DeMeo. Grant. Milligan, and Schuerger , " Wind Plant Integration: Costs, Status, and Issues , IEEE Power & En- ergy Magazine, Vol 3 Number 6, Nov/Dec 2005, p. 41. 190 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology Figure J.I- Load Following Reserve Requirement Illustration 'U "-""'---'-""""""" '",__"""'"',"",-'"",---"""---,,,- "m........-... ...J -------------------------------..:~=~g -':=-t ~ - m-mm- ....._/... ;;0 ::J --.-""'-----.......---....-...--...--------- -rn----------- .-.--..-.-.------..-...----...---......---......---......---......--.........-.-...-...----...----------....------....--...-----...-----.----...---------...--------...... -....----...-----....----......--...--------....-----....----...--....------...-..-----..---..--. --..-.-. . -... - .---.-.......-- .-. ..-... - .-..-............--.--.-. --- - ...-.-...-----.-- -.---.-. --------....----. - --.---.- - ---- Begin Hour 1 Begin Hour 2 Figure J.2 shows the variability of the load forecast and the variability of the wind energy rolled together by performing the same analysis on the forecast of load net of wind energy. The ex- pected value of load net of wind wiH be less than or equal to the load forecast for any given hour. However, the variability of load net of wind is greater than that of load alone. It is the difference of between the variability of load and the variability of load net of wind for a given hour that described the incremental reserves that should be attributed to wind resources. Figure J.2 - Load Following Reserve Requirement for Load Net of Wind ..-...-..----..-..------.-...-----.---...--..--.-.......-..-..-......-..-.---.-...-...-...-..-..--.....--......--.... ....-...-......-.--..----_..._-.. -- - ....---..........-......-......__.._.._.._--......~.)...- Q) Effect of Wind Z --........------------------------... ----.--...--.-..-.-......-...-----...-...---...-.-....-...-.-... ...-.--.---.......---...-...--..-..-..-..-..- - ----.-----....-.-..-------.....--...-------------.---. ~ 95% ;;0 """'-"-'---"---'----_""_0_"__"'...1 ... -....... Load Following Reserves wI Wind -l.- lion _. -- ._~_..__---_.._--_.._...... W -. , ---------_:~~~~:~~:-~"'--- bOad~_~L~f ~in~ ~___------- ~---- - 1------------... Begin Hour 1 Begin Hour 2 191 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology Early in the 2007 IRP process, the result of applying this methodology to the PacifiCorp system with an additional 1,400 megawatts of wind resources was an estimated 30 megawatts of addi- tional reserve requirements. That amount of spinning reserve was added to the stochastic PaR model runs to simulate the additional cost. In fol1ow up analyses of the preferred portfolio, the company confirmed that using even the sim- plest forecast techniques greatly reduced the forecast error of both load and wind and conse- quently reduced the anticipated need for load following reserves. Figure 1.3 displays the esti- mated incremental load fol1owing requirement calculated using PacifiCorp s updated load fore- cast and varying the level of wind resources following the build pattern of the preferred portfolio. F or the 1,400 megawatt level of wind installation, the estimated need for incremental reserves is approximately 22 megawatts. For the preferred portfolio with 2 000 megawatts of wind re- sources, Figure 1.4 shows an estimated need for 43 megawatts of additional load following re- serves due to wind resources. This analysis represents a reduction in the estimate of needed reserves compared with previous estimates. The major difference from prior studies is the development of a systematic method for estimating load fol1owing reserve requirements. The 2003 IRP study was based on the hourly variability of wind resources, whereas the current analysis is based on the hourly uncertainty in generation. It is further benefited by the more extensive operating data available since the 2003 ~. Figure J.3 - Incremental Reserve Cost Associated with Various Wind Capacity Amounts Incremental Reserve Requirement as a Function of Installed Wind Resources CJ) c= ;:: CJ) :IE en CJ)~ C S E i ~ ~ .... CJ) g ~ 2 = 0.9156 500 1000 1500 2000 2500 Installed Wind Capacity (MW) By running the PaR model studies with and without the incremental load following reserves, the company can estimate the cost of the incremental reserves at varying levels. This can be con- 192 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology verted to a unit cost by dividing the cost by the total amount of wind energy. Figure JA shows the results of those studies. Figure J.4 - Operating Cost of Incremental Load Following Reserves Cost of Incremental Reserves for 2000 MW of Wind 2007$ Based on RA 14 ~ $3. :!E~ $2. ~ $2. ~ $1. 111 $1 . '0 $0. ~ $0. y = 0.0175x 1OO6 R2 = 0.9995 40 :100 Reserve Increment (MW) From Figure JA, the unit cost of 43 megawatts of incremental reserves attributed to the 2 000 megawatts of wind capacity in the preferred portfolio is estimated to be $1.10 per megawatt hour of wind energy. System Balancin2 Costs System balancing costs represent the additional operating costs incurred as a result of adding wind generation to PacifiCorp s system. For the 2003 IRP, the system balancing costs associated with wind resources were evaluated by comparing one model run with wind resources specified with an hourly energy pattern to another run where the hourly wind energy was replaced by an equal amount of energy expressed as a flat annual shape. This methodology was repeated for the 2007 IRP preferred portfolio with the following modifications. First, the hourly wind patterns for the base study were substantially upgraded. Data from multiple Pacific Northwest sources, including PacifiCorp s actual wind energy, was modified for project size and mapped to the proxy wind resources by location. In the case of multiple "plants " some of the data was shifted by an hour or two to represent di- versity within a wind area. The Wyoming projects were updated to a 40 percent capacity factor to be consistent with actual information coming from that area. The comparison to the annual block size was repeated for several sized accumulations of wind projects across PacifiCorp s system using the wind data and build patterns consis- tent with the preferred portfolio analysis. 193 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology Using the equivalent annual block against the hourly wind patterns confirmed earlier findings that as wind resources accumulate the system balancing costs also increase on a unit cost basis. The 2007 IRP results are shown in Figure J.5. The results are similar to previous studies. Figure J.5 - PacifiCorp System Balancing Cost - 5. .t: 3: 4.~ 3. ~ 2. ... ~ 1.0 0. System Balancing Cost as a function of Installed Wind Capacity (MW) 10 Year Levelized $2007 y = 0.002x 2 = 0.9415 500 1000 1500 2000 2500 Installed Wind (MW) From Figure J.5 it can be seen that 2000 megawatts of wind capacity installed on PacifiCorp system brings with it approximately $4.00 per megawatt-hour less than an equivalent amount of energy shaped as an annual base load resource While some of the regional studies employed smaller sized energy blocks for similar compari- sons, PacifiCorp continues to use the annual block-size approach. Equivalent energy generated at a constant rate for the entire year and priced at market is the competing resource that Pacifi- Corp uses in its resource economic evaluations. Use of Wind Inte2ration Cost Estimates in the 2007 IRP Portfolio Analvsis Wind integration costs for the purposes of the CEM runs were based on 2004 IRP results due to the timing of the needed analyses. In the PaR model, the system balancing costs are implicit as the wind resources are represented as hourly generation patterns from the quasi-historical data. The incremental load-following reserve requirement, calculated outside of the main IRP models was added as a constraint in the stochastic PaR runs for the candidate and preferred portfolios in the 2007 IRP. (CEM does not model reserve requirements, and so was not affected by the analy- sis). 194 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology Because the hourly generation patterns of wind and the increased incremental reserves are mod- eled explicitly in the PaR model the PVRR includes both types of cost. The integration cost for the 2 000 megawatts of wind resources included in the preferred portfolio is estimated to be $5.10 per megawatt hour of wind energy. PacifiCorp is continuing to explore methodologies to confirm and quantify wind variability with respect to the need for operating reserves. In particular, sub-hourly data is being captured to test the impact of deviations within the hour. Continued study of the impacts of integrating large quantities of wind in PacifiCorp s system is identified in the IRP action plan (See Chapter 8). . '... .. DE TERMIN ATIO NOFC OST.'"EFFEC TlVEWINDRE SOURCE PacifiCorp used the CEM to help determine the quantity of wind considered reasonable given a range of alternative assumptions concerning future portfolio costs. The explicit costs of wind (capital and integration costs, less production tax credits and the value of renewable energy cred- its) were entered into the CEM. The results of the alternative future scenario CEM runs were examined to find a rough cost-effectiveness order for the proxy wind resource sites. Nearly all of the CEM runs found wind to be part of a cost-effective resource portfolio. Fixed in each of the runs were the 400 megawatt MEHC acquisition commitments made to state commissions. In the "medium case" alternative future scenario (Alternative Future #11), the CEM added 700 nameplate megawatts of wind resources to the system, for a total of 1 100 megawatts of additional renewable resources by 2016. Figure J.6 shows the cost-effective wind capacity amounts (both nameplate and capacity contri- bution) selected by the CEM for each of the 16 alternative future scenarios. The average for all the alternative future runs was over 1 200 megawatts (235 megawatt capacity contribution), or 600 megawatts including the 400 megawatt base assumption quantity. These results are consis- tent with the 1 400 megawatt determination for the level of cost-effective renewables reported in PacifiCorp s 2004 IRP. 195 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology Figure J.6 - Renewables Capacity Additions for Alternative Future Scenarios II) 0') (I) 500 000 500 000 500 000 500 CAFOO CAF01 CAF02 CAF03 CAF04 CAF05 CAFO6 CAFO7 CAF08 CAFO9 CAF10 CAF11 CAF12 CAF13 CAF14 CAF15 Ave. m Wind Capacity Contribution 82 196 60 277 259 215 354 514 514 85 148 95 222 99 410 235 . Renew abies Narreplate 300 1 000 400 1,400 1,400 1,400 2 200 3 100 - 3 100 400 700 400 900 400 2,300 1213 1m Wind Capacity Contribution . Renewables Nameplate A CEM sensitivity run was performed to test the quantity of wind selected given the expiration of renewable production tax credits, but with otherwise favorable scenario conditions for wind development. These favorable conditions included a high CO2 adder ($25/ton in 1990 dollars), high natural gas and electricity prices, and a high system-wide renewable sales percentage re- quirement attributable to renewable portfolio standards. See Chapter 6, Modeling and Risk Analysis Approach, for more details on scenario assumptions. In this sensitivity, the CEM selected 1 900 megawatts of wind by 2016 (capacity contribution of 335 megawatts). Figure J.7 shows the cumulative annual resource addition pattern for 2008 through 2016. The sensitivity results indicate that given the assumed favorable scenario condi- tions, the expiration of the production tax credits results in 1 200 megawatts less wind capacity selected for the optimal portfolio. Based on these results, PacifiCorp identified 1 000 to 1 600 megawatts of additional nameplate wind capacity for specifying proxy renewable resources to be included in portfolios subjected stochastic production cost simulation. 196 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology Figure J.7 - Cumulative Capacity Contribution of Renewable Additions for the PTC Sensi- tivity Study 000 800 600 1 ,400 200 000 800 600 400 200 2007 900 2008 2009 2010 2012 2014 2015 201620112013 E!I Capacity Contribution (MW) .. Nameplate (MW) WI~D CAPACITYPLANNING CONTRIBUTION For planning purposes, most resources are assumed to contribute their nominal (or "nameplate capacity to meeting the planning reserve margin level. It is recognized that wind resources can- not be depended on to contribute their full nameplate capacity to meeting planning reserve mar- gin, since the probability of achieving that level on a peak hour is relatively low, and virtually zero for a large portfolio of diverse wind resources. Nevertheless, it was recognized that some level of capacity contribution attributed to wind projects is appropriate, and PacifiCorp has adopted the effective load carrying capability of wind projects as the standard. In short, the ef- fective load carrying capability of a resource is the amount of incremental load the system can meet with the incremental resource without degrading the reliability of meeting load. PacifiCorp used the stochastic PaR model to estimate the monthly load carrying capability of a wind resource using an analytical method based on the Z statistic.5 The analytical method of es- timating load carrying capability was necessary in order to compute the capacity contributions from a large number of wind projects and different combinations of projects. The result of this analysis as applied to the proxy (lOO-megawatt) wind resources is shown in Table J.l below. Key observations from these results include the following. 5 See. Dragoon. K., Dvortsov, V , " Z-method for power system resource adequacy applications IEEE Transactions on Power Svstems (Volume 21 , Issue 2, May 2006), pp. 982 - 988. 197 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology The incremental capacity contribution within an area declines due to correlations (lack of diversity) among wind projects in an area. The capacity contribution decline is greatest for projects with more variability of their on- peak contributions. The capacity contribution varies over the year, primarily due to expected on-peak generation. Table J.I- Incremental Capacity Contributions from Proxy Wind Resources Regional Resource Additions (MW)Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec NC OR -100 200 300 400 SEWA 100 200 300 400 ECNV 100 200 300 400 SE 10 100 200 300 400 WCUT 100 200 300 400 SW WY -100 200 300 400 500 600 700 SCMT 100 200 300 -400 SEWY 100 200 300 400 500 600 700 198 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology .. . . .......... REGIONALSTUDmS Utilities are studying wind resources in order to quantify the full cost of integrating wind energy into existing systems. In March 2007 Northwest Power and Conservation Council released the Northwest Wind Integration Action Plan (the Action Plan). A joint product of the region s util- ity, regulatory, consumer and environmental organizations, the Action Plan addresses several major questions surrounding the growth of wind energy and suggests areas that need further con- sideration. The Action Plan summarizes the results of wind integration cost studies performed by PacifiCorp (in its 2004 IRP), A vista, Idaho Power, Puget Sound Energy, and Bonneville Power. The report lists the key findings of these northwest studies. All of the studies find that the cost of integrat- ing wind starts low as the variability of small quantities of wind generation is lost in the volatility of the system load, and grows as the amount of wind resource increases. Collectively the studies list the size of the control area in relation to the amount of wind, the geographic diversity of the wind locations, the amount of flexibility of the receiving utility, and the access to robust markets as key factors affecting the cost of integrating wind energy. Table J.2 reproduces the data from the report. The Action Plan includes a summary of each the study methodologies in its appendix B. PacifiCorp s estimate of wind integration costs ranked among the lowest of the wind integration costs. Only Bonneville Power ranked lower. PacifiCorp s low integration cost is likely the result of the opportunity to maximize the use of each of the key factors: a large system, wide geographic coverage allowing for dispersed wind sites, and a flexible system with multiple points of access to the energy markets. Table J.2 - Wind Integration Costs from Northwest Utility Studies Wind Penetration $/MWh of Wind Generation5%. 10% 200/0 30% $ 2.75 $ 6.99 $ 6.65 $ 8. $ 9.75 $11.72 $16. $ 4. $ 3.19 $ 5. $ 2.40 $ 3.70 $ 4. Peak Load (MW) 200 100 650 9,400 090 $ 3. $ 1.86 $ 1.90 In the wake of the regional load peak of July 24 2006 when wind turbines made only a small contribution to generating capacity at the time of the peak, the wind resource contribution to peak capacity is being reassessed by Northwest Resource Adequacy Forum (NWRA Forum) as Action #1 of the Action Plan. 6 Source: NWRA Forum, Northwest Wind Integration Action Plan, (March 2007 pre-publication version), page 31. 7 NWRA Forum Northwest Wind Integration Action Plan (March 2007 pre-publication version). See Action 1 pA8 199 PacifiCorp 2007 IRP Appendix J Wind Resource Methodology EFFECT OFRESOURC . ' . t'fIONiFIJELT~E ONTHECOMPAN~'SCO~TTO IN"TEGRATEWlNI)~S()J!RCES . . / As the company installs larger volumes of wind resource generation, the cost to integrate these intermittent resources is anticipated to increase. This is because more non-wind resources must be held back to allow flexibility to follow the intra-hour volatility of the wind generation. Re- sources with greatest the dispatch flexibility that are not already in use to serve load are typicany used for integration. The hour to hour dispatch of non-wind resources is not a trivial decision. The company s owned hydro plants with storage capability and the Mid-Columbia hydro contracts, an of which have the highest flexibility, can often provide the needed flexibility. However, these hydro resources do not have enough volume to integrate an of the anticipated wind variability. Partially loaded gas turbines can provide additional flexibility. Due to its low cost, coal is normany funy utilized to serve load rather than backed off to provide wind integration. It is flexible resources that are operating on the margin that influence the cost of wind integra- tion. When evaluating the effect of the fuel type of resource additions on PacifiCorp s cost to integrate wind resources, it is most likely that the IRP natural gas-fired additions will have the most effect on integration costs. 200